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

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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

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
[email protected]
[email protected]
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

V.

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

i

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

1

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

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

6

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.

3

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

4



TPL-004-0.

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

I.

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.

5

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

7

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
[email protected]
[email protected]

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

6

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

8

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

7

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).

8

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

13

Order 693 at P 1794.

9

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.

10

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.

18

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

11

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

23

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.

12

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).

13

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.

28

See Exhibit G to this petition.

14

V.

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.

15

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]

16

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

17

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,

18

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

29

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.

19

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

30

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.”).

20

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

21

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.

31

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.”).

22

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
[email protected]
[email protected]
Counsel for North American Electric
Reliability Corporation

23

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

2.

Number:

3.

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.

4.

Applicability:

TPL-001-4

4.1. Functional Entity

5.

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)

1

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.

2

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.

3

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
4

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.

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:
4.3.1.1.

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.

6

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.

7

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

No

No

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

No

HV

Yes

Yes

Event 1

Initial Condition

Normal System

Normal System

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

2.

SLG

Opening of a line section w/o a fault

7

N/A

Bus Section Fault

SLG

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

8

4. Internal Breaker Fault (Bus-tie Breaker)

EHV

9

No

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

8

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

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
adjustments9

Event

1

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

No

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
9

SLG

SLG

9

SLG

3Ø

SLG

9

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

Initial Condition

Normal System

Event

1

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

Yes

10

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

11

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).

13

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

R1

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.

R2

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.

R3

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.

18

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

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

19

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

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

20

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

E.

Regional Variances
None.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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)

2

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

2

August 4, 2011

Adopted by Board of Trustees

1

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.

3

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.

4

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

2.

Number:

3.

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.

4.

Applicability:

TPL-001-24

4.1. Functional Entity

5.

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:










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)

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

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Standard TPL-001-24 — 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.

Adopted by NERC Board of Trustees: August 4, 2011

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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.

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.

Adopted by NERC Board of Trustees: August 4, 2011

3

Standard TPL-001-24 — 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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner

Adopted by NERC Board of Trustees: August 4, 2011

4

Standard TPL-001-24 — 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

Adopted by NERC Board of Trustees: August 4, 2011

5

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.

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.

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:
4.3.1.1.

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.

Adopted by NERC Board of Trustees: August 4, 2011

6

Standard TPL-001-24 — 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: LowerMedium] [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: LowerLow] [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.

Adopted by NERC Board of Trustees: August 4, 2011

7

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

Adopted by NERC Board of Trustees: August 4, 2011

8

Standard TPL-001-24 — 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

No

No

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

No

HV

Yes

Yes

Event 1

Initial Condition

Normal System

Normal System

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

2.

SLG

Opening of a line section w/o a fault

7

N/A

Bus Section Fault

SLG

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

8

4. Internal Breaker Fault (Bus-tie Breaker)

Adopted by NERC Board of Trustees: August 4, 2011

EHV

9

No

No

HV

Yes

Yes

EHV, HV

Yes

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

1

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

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

No

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
9

SLG

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

1

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

Yes

Standard TPL-001-24 — 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.

Adopted by NERC Board of Trustees: August 4, 2011

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-001-24 — 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).

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — 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
Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — 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.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — 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.

Adopted by NERC Board of Trustees: August 4, 2011

Standard TPL-001-24 — 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
Adopted by NERC Board of Trustees: August 4, 2011

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

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

19

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

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

20

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

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

21

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

E.

Regional Variances
None.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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)

2

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

2

August 4, 2011

Adopted by Board of Trustees

1

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.

3

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.

4

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.

Adopted by NERC Board of Trustees: August 4, 2011

18

Exhibit B
Implementation Plan for the Consolidated TPL Reliability Standard

Implementation Plan for TPL-001-4
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
TPL-001-4 — Transmission System Planning Performance Requirements
In revising the TPL standards, the SDT is assuming that planners will receive valid data from the MOD
standards link described in TPL-001-4, Requirement R1. Furthermore, there is a tacit assumption that
future revisions of the MOD standards will include steps to validate MOD based data.
Revision to Sections of Approved Standards and Definitions
There are multiple new definitions in the proposed standard.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission System performance and
Corrective Action Plans to remedy identified deficiencies.

Compliance with Standards
Standard
TPL-001-4 — Transmission
System Planning Performance
Requirements

Functions That Must Comply With the Associated Requirements
Transmission Planner
Planning Coordinator
XX

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this standard.
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.

1

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)

TPL-001-3, TPL-002-2b, TPL-003-2a, and TPL-004-2 are being retired as they are replaced in their
entirety by TPL-001-4. TPL-005-0 and TPL-006-0.1 are being retired because their requirements are
adequately covered by the revised TPL-001-4 and NERC’s Rules of Procedure, Section 800. TPL-001-3,
TPL-002-2b, TPL-003-2a, TPL-004-2, TPL-005-0 and TPL-006-0.1 are being retired on midnight of the
day immediately prior to the Effective Date of TPL-001-4 in the particular jurisdictions in which TPL001-4 is becoming effective. However, during this 24-month period, all aspects of TPL-001-3 through
TPL-006-0.1 shall remain in effect for compliance monitoring. This 24 month period is to allow entities
to develop, perform and/or validate new and/or modified studies, methodologies, assessments,
procedures, etc. necessary to implement and meet the TPL-001-4 requirements. The specified effective
dates are expected to allow sufficient time for proper assessment of the available options necessary to
create a viable Corrective Action Plan that is compliant with the new Standard.
R1. This Requirement is related to maintaining System models and the data needed to do so. This
requirement shall become effective on the first day of the first calendar quarter, 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
this requirement goes into effect on the first day of the first calendar quarter, 12 months after
Board of Trustees adoption.
R7. This Requirement identifies an obligation to determine individual and joint responsibilities
for performing studies needed to do the Planning Assessment. This requirement shall become
effective on the first day of the first calendar quarter, 12 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, this requirement goes

2

into effect on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption.
TPL-001-4 ‘raises the bar’ in several areas where performance requirements have been changed in the new
Standard versus those in existing TPL-001-3, TPL-002-2b, TPL-003-2a and TPL-004-2 because loss of NonConsequential Load or interruption of firm transfers is no longer allowed for certain events, whereas the
existing Standards were interpreted by many to allow such actions. As shown in Table 1 of TPL-001-4, the
performance requirements associated with the following events represent “raising the bar”:









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)

This “raising the bar” is beyond the control of the Transmission Planner and Planning Coordinator and
may have significant budget, siting, permitting, and construction impacts on many Transmission Owners.
To provide stakeholders with sufficient time to implement changes, a timeframe coincident with the end
of the Near-Term Transmission Planning Horizon has been provided
Any entity which cannot eliminate the need to trip Non-Consequential Load or curtail Firm Transmission
Service for these performance elements by that date shall submit a mitigation plan to its Regional Entity
outlining the steps it will take to correct the problem. If the entities follow the established ERO procedure
for mitigation, it is the intent of the SDT that no penalties will be assessed.

3

Exhibit C
Proposed Individual TPL Reliability Standards submitted for Approval

Standard TPL-001-3 — System Performance Under Normal Conditions

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-3

3.

Purpose: System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements with
sufficient lead time, and continue to be modified or upgraded as necessary to meet present
and future system needs.

4.

Applicability:
4.1.

Planning Authority

4.2.

Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities. All other requirements remain in effect per previous approvals.
The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes
effective.

B.

Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

Page 1 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-3_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-3_R1 and TPL-0013_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-3_R3.

Page 2 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

D.

Compliance
1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via
the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E.

Regional Differences
1. None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

Revised

FERC Approved – Updated Effective Date and
Footer

Page 3 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

1

Approved by
Board of
Trustees
February 17,
2011

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised (Project 201011)

2

August 4, 2011

Revision of TPL-001-1; includes merging and
upgrading requirements of TPL-001-0, TPL-0020, 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

2

August 4, 2011

Adopted by Board of Trustees

1

April 19, 2012

FERC issued Order 762 remanding TPL-001-1,
TPL-002-1b, TPL-003-1a, and TPL-004-1. FERC
also issued a NOPR proposing to remand TPL001-2. NERC has been directed to revise footnote
'b' in accordance with the directives of Order Nos.
762 and 693.

3

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-0010.1, TPL-002-0b, TPL-003-0a, and TPL-004-0.

Page 4 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e

Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

No

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Gener ator

Page 5 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. For purposes of this
footnote, the following are not counted as Firm Demand: (1) Demand directly served by the Elements removed
from service as a result of the Contingency, and (2) Interruptible Demand or Demand-Side Management Load.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES
performance requirements are met. However, when interruption of Firm Demand is utilized within the NearTerm Transmission Planning Horizon to address BES performance requirements, such interruption is limited to
circumstances where the use of Firm Demand interruption meets the conditions shown in Attachment 1. In no
case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered entities.
The amount of planned Non-Consequential 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.
c)Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.

Page 6 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Page 7 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under
footnote ‘b’ 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 ‘b’ 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 Firm Demand interruption under
footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm
Demand interruption under footnote ‘b’ (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 ‘b’ 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 Firm Demand interruption
under footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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

Page 8 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

2. Amount of Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Firm Demand interruption under
footnote ‘b’ on the health, safety, and welfare of the community
3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on
historical performance
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on
historical performance
5. Future plans to alleviate the need for Firm Demand interruption under footnote ‘b’
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote ‘b’
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with
adjacent Transmission Planners and Planning Coordinators
III. Instances for which Regulatory Review of Interruptions of Firm Demand under
Footnote ‘b’ is Required
Before a Firm Demand interruption under footnote ‘b’ 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
Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’,
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 Firm Demand interruption under footnote ‘b’ 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 Firm

Page 9 of 10

Standard TPL-001-3 — System Performance Under Normal Conditions

Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

Page 10 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-0.13

3.

Purpose: System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements with
sufficient lead time, and continue to be modified or upgraded as necessary to meet present
and future system needs.

4.

Applicability:
4.1.

Planning Authority

4.2.

Transmission Planner
May 13, 2009

5.Effective Date:
5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption or as otherwise made effective pursuant to the laws applicable to such ERO
governmental authorities. All other requirements remain in effect per previous approvals.
The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes
effective.

B.

B.

Requirements

R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.
Page 1 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-03_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-03_R1 and TPL-00103_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-03_R3.

Page 2 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions

D.

D.

Compliance

1. Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via
the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E.

E.

Regional Differences

1. None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

Revised

FERC Approved – Updated Effective Date and
Footer

Page 3 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions

1

Approved by
Board of
Trustees
February 17,
2011

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised (Project 201011)

2

August 4, 2011

Revision of TPL-001-1; includes merging and
upgrading requirements of TPL-001-0, TPL-0020, 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

2

August 4, 2011

Adopted by Board of Trustees

1

April 19, 2012

FERC issued Order 762 remanding TPL-001-1,
TPL-002-1b, TPL-003-1a, and TPL-004-1. FERC
also issued a NOPR proposing to remand TPL001-2. NERC has been directed to revise footnote
'b' in accordance with the directives of Order Nos.
762 and 693.

3

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-0010.1, TPL-002-0b, TPL-003-0a, and TPL-004-0.

Page 4 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e

Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

No

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Gener ator

Page 5 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. For purposes of this
footnote, the following are not counted as Firm Demand: (1) Demand directly served by the Elements removed
from service as a result of the Contingency, and (2) Interruptible Demand or Demand-Side Management Load.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES
performance requirements are met. However, when interruption of Firm Demand is utilized within the NearTerm Transmission Planning Horizon to address BES performance requirements, such interruption is limited to
circumstances where the use of Firm Demand interruption meets the conditions shown in Attachment 1. In no
case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered entities.
The amount of planned Non-Consequential 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.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.

Page 6 of 10

Standard TPL-001-0.13 — System Performance Under Normal Conditions
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

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Standard TPL-001-0.13 — System Performance Under Normal Conditions

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under
footnote ‘b’ 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 ‘b’ 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 Firm Demand interruption under
footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm
Demand interruption under footnote ‘b’ (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 ‘b’ 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 Firm Demand interruption
under footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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

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Standard TPL-001-0.13 — System Performance Under Normal Conditions

2. Amount of Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Firm Demand interruption under
footnote ‘b’ on the health, safety, and welfare of the community
3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on
historical performance
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on
historical performance
5. Future plans to alleviate the need for Firm Demand interruption under footnote ‘b’
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote ‘b’
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with
adjacent Transmission Planners and Planning Coordinators
III. Instances for which Regulatory Review of Interruptions of Firm Demand under
Footnote ‘b’ is Required
Before a Firm Demand interruption under footnote ‘b’ 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
Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’,
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 Firm Demand interruption under footnote ‘b’ 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 Firm

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Standard TPL-001-0.13 — System Performance Under Normal Conditions

Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-2b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of the
first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History

Version

Date

Action

Change Tracking

0

February 8, 2005

Adopted by NERC Board of Trustees

New

0

April 1, 2005

Effective Date

New

0a

July 30, 2008

Adopted by NERC Board of Trustees

New

0a

October 23, 2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5, 2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Interpretation

FERC Order issued approving the
Interpretation of R1.3.10 (FERC Order
becomes effective October 24, 2011)

Interpretation

Revised footnote ‘b’ pursuant to FERC

Revised

0b Septem

1b

2011

ber 15,

April 2010

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
Order RM06-16-009.
Approved by the Board of Trustees; revised
footnote ‘b’ pursuant to FERC Order
RM06-16-009

1b

February 17, 2011

1b

April 19, 2012

FERC issued Order 762 remanding TPL001-1, TPL-002-1b, TPL-003-1a, and TPL004-1. 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.

2b

February 7, 2013

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

Revised (Project 201011)

Page 4 of 13

Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

Page 5 of 13

Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section
e

3Ø Fault, with Normal Clearing :

Evaluate for risks and
consequences.




5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout
the planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm
Demand is utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements,
such interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US
registered entities. The amount of planned Non-Consequential 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.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
Page 7 of 13

Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

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

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Page 9 of 13

Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)


Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard TPL-002-0b2b — System Performance Following Loss of a Single BES Element
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-0b2b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: Immediately after approval of applicable regulatory authorities.

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of the
first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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Standard TPL-002-0b2b — System Performance Following Loss of a Single BES Element
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-01_R1 and TPL-002-01_R2.

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Standard TPL-002-0b2b — System Performance Following Loss of a Single BES Element
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History

Version

Date

Action

Change Tracking

0

February 8, 2005

Adopted by NERC Board of Trustees

New

0

April 1, 2005

Effective Date

New

0a

July 30, 2008

Adopted by NERC Board of Trustees

New

0a

October 23, 2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5, 2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Interpretation

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Standard TPL-002-0b2b — System Performance Following Loss of a Single BES Element
0b

September 15,
2011

FERC Order issued approving the
Interpretation of R1.3.10 (FERC Order
becomes effective October 24, 2011)

Interpretation

1b

April 2010

Revised

1b

February 17, 2011

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.
Approved by the Board of Trustees; revised
footnote ‘b’ pursuant to FERC Order
RM06-16-009

1b

April 19, 2012

FERC issued Order 762 remanding TPL001-1, TPL-002-1b, TPL-003-1a, and TPL004-1. 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.

2b

February 7, 2013

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

Revised (Project 201011)

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Standard TPL-002-0b2b — System Performance Following Loss of a Single BES Element
Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section
e

3Ø Fault, with Normal Clearing :

Evaluate for risks and
consequences.




5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout
the planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm
Demand is utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements,
such interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US
registered entities. The amount of planned Non-Consequential 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.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

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

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)


Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Standard TPL-002-2b — System Performance Following Loss of a Single BES Element

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES Elements
A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-2a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective date
will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES Elements
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-2_R1, the Planning Authority and Transmission Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

B. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-2_R1 and TPL-003-2_R2.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES Elements
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-2_R3.
C. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
D. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

February 8, 2005

Adopted by NERC Board of Trustees

New

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

July 30, 2008

Adopted by NERC Board of Trustees

0a

October 23, 2008 Added Appendix 1 – Interpretation of
TPL-002-0 Requirements R1.3.2 and
R1.3.12 and TPL-003-0 Requirements
R1.3.2 and R1.3.12 for Ameren and
MISO

Revised

0a

April 23, 2010

Interpretation

FERC approval of interpretation of TPL003-0 R1.3.12

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES Elements

1a February
2011

17,

1a

April 19, 2012

2a

February 7, 2013

Approved by the Board of Trustees;
revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.
FERC issued Order 762 remanding TPL001-1, TPL-002-1b, 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.

Revised (Project 201011)

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES Elements

Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Cascading c
Voltage
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements
D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm Demand is
utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements, such
interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered
entities. The amount of planned Non-Consequential 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 nonUS jurisdiction.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements

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

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.
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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)


Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Standard TPL-003-2a — System Performance Following Loss of Two or More BES
Elements
Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements
A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-0a2a

4.1. Planning Authority
4.2. Transmission Planner
April 23, 2010

5.

Effective Date:

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective date
will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-02_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

C.B.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.
Measures

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-02_R1 and TPL-003-02_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-02_R3.
D.C.

Compliance

1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
Regional Differences

E.D.
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

February 8, 2005

Adopted by NERC Board of Trustees

New

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

July 30, 2008

Adopted by NERC Board of Trustees

0a

October 23, 2008 Added Appendix 1 – Interpretation of
TPL-002-0 Requirements R1.3.2 and
R1.3.12 and TPL-003-0 Requirements
R1.3.2 and R1.3.12 for Ameren and
MISO

Revised

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements

0a

April 23, 2010

FERC approval of interpretation of TPL003-0 R1.3.12

Interpretation

1a

February 17,
2011

Revised (Project 201011)

1a

April 19, 2012

Approved by the Board of Trustees;
revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.
FERC issued Order 762 remanding TPL001-1, TPL-002-1b, 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.

2a

February 7, 2013

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements

Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Cascading c
Voltage
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

Page 4 of 4

Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements
D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm Demand is
utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements, such
interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered
entities. The amount of planned Non-Consequential 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 nonUS jurisdiction.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements

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

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.
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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
Elements

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)


Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Standard TPL-003-0a2a — System Performance Following Loss of Two or More BES
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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard TPL-004-2 — System Performance Following Extreme BES Events
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number: TPL-004-2

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective date
will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that would
produce the more severe system results or impacts. The rationale for the
contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would produce
less severe system results shall be available as supporting information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

1 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those demand
levels for which planned (including maintenance) outages are performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
B. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-2_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-2_R1.
C. Compliance
1.

2.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2: Not

applicable.

2.3.

Level 3: Not

applicable.

2.4. Level 4: Not
D. Regional Differences

applicable.

1.

None identified.

2 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events
Version History
Version

Date

0
April 1, 2005
1 February
17,
2011
1

April 19, 2012

2 February
2013

7,

Action

Change Tracking

Effective Date
Approved by the Board of Trustees;
revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.
FERC issued Order 762 remanding
TPL-001-1, TPL-002-1b, 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.

New
Revised (Project 201011)

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

3 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

4 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm Demand is
utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements, such
interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered
entities. The amount of planned Non-Consequential 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 nonUS jurisdiction.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

5 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected

6 of 7

Standard TPL-004-2 — System Performance Following Extreme BES Events

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

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.

7 of 7

Standard TPL-004-02 — System Performance Following Extreme BES Events
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number: TPL-004-

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

02

4.1. Planning Authority
4.2. Transmission Planner

B.

April 1, 2005

5.

Effective Date:

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after approval by applicable regulatory
authorities. In those jurisdictions where regulatory approval is not required, the effective date
will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or
as otherwise made effective pursuant to the laws applicable to such ERO governmental
authorities. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.
B. Requirements

R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that would
produce the more severe system results or impacts. The rationale for the
contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would produce
less severe system results shall be available as supporting information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.

Adopted by NERC Board of Trustees: February 8, 2005
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Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events
R1.3.5. Include existing and planned facilities.
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those demand
levels for which planned (including maintenance) outages are performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C.B. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-02_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-02_R1.
D.C. Compliance
1.

2.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2: Not

applicable.

2.3.

Level 3: Not

applicable.

2.4. Level 4: Not
E.D. Regional Differences

applicable.

1.

None identified.

Adopted by NERC Board of Trustees: February 8, 2005
2 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events
Version History
Version

Date

Action

Change Tracking

0
1

April 1, 2005
February 17,
2011

New
Revised (Project 201011)

1

April 19, 2012

Effective Date
Approved by the Board of Trustees;
revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.
FERC issued Order 762 remanding
TPL-001-1, TPL-002-1b, 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.

2

February 7,
2013

Adopted by NERC Board of Trustees.
Revised footnote ‘b’.

Adopted by NERC Board of Trustees: February 8, 2005
3 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Gener ator
2. Transmission Circuit
3. T ransformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

e

No

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. T ransformer

Yes

Planned/
Controlledc

No

8. T ransmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Gener ator

Adopted by NERC Board of Trustees: February 8, 2005
4 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Gener ator

3. T ransformer

2. T ransmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm Demand is
utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements, such
interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for US registered
entities. The amount of planned Non-Consequential 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 nonUS jurisdiction.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

Adopted by NERC Board of Trustees: February 8, 2005
5 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ would be
necessary:
a. System Load level and estimated annual hours of exposure at or above that Load
level
Adopted by NERC Board of Trustees: February 8, 2005
6 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events

2.

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

b. Applicable Contingencies and the Facilities outside their applicable rating due to
that Contingency
Amount of Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An explanation of the effect of the use of Firm Demand interruption under
footnote ‘b’ on the health, safety, and welfare of the community
Estimated frequency of Firm Demand interruption under footnote ‘b’ based on historical
performance
Expected duration of Firm Demand interruption under footnote ‘b’ based on historical
performance
Future plans to alleviate the need for Firm Demand interruption under footnote ‘b’
Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote ‘b’
Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent
Transmission Planners and Planning Coordinators

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ 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 Firm Demand interruption
Adopted by NERC Board of Trustees: February 8, 2005
7 of 8
Effective Date: April 1, 2005

Standard TPL-004-02 — System Performance Following Extreme BES Events

under footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.

Adopted by NERC Board of Trustees: February 8, 2005
8 of 8
Effective Date: April 1, 2005

Exhibit D
Implementation Plan for the Individual TPL Reliability Standards

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-3: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-2b: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-2a: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-2: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
XX

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
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requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

Exhibit E
Order No. 672 Criteria

EXHIBIT E
Order No. 672 Criteria
In Order No. 672, 1 the Commission identified a number of criteria that it will use
to analyze Reliability Standards proposed for approval to ensure that a proposed Standard
is just, reasonable, not unduly discriminatory or preferential, and in the public interest.
The discussion below identifies these factors, and explains how the Footnote and the
Proposed TPL Standards meet or exceed the criteria: 2
1.

Proposed Reliability Standards must be designed to achieve a specified
reliability goal and must contain a technically sound means to achieve that
goal. 3
The proposed Footnote is designed to provide specificity and consistency in order

to allow for planned load shed for single Contingencies. The Commission found that the
existing footnote is ambiguous and could result in inconsistent application, because,
among other reasons, there were no limitations on maximum usage. The proposed
Footnote establishes an open and transparent process with affected stakeholders and

1

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006) (together, “Order
672”)).
2
Capitalized terms used but not defined in this Attachment A are intended to have the same
meaning given to such terms in the Petition, the Proposed Standards or the Glossary of Terms Used in
NERC Reliability Standards, available at: http://www.nerc.com/files/Glossary_of_Terms.pdf.
3
Id. at P 321. The proposed Reliability Standard must address a reliability concern that falls
within the requirements of Section 215 of the FPA. That is, it must provide for the reliable operation of
Bulk-Power System facilities. It may not extend beyond reliable operation of such facilities or apply to
other facilities. Such facilities include all those necessary for operating an interconnected electric energy
transmission network, or any portion of that network, including control systems. The proposed Reliability
Standard may apply to any design of planned additions or modifications of such facilities that is necessary
to provide for reliable operation. It may also apply to Cybersecurity protection.
Id. at P 324. The proposed Reliability Standard must be designed to achieve a specified reliability
goal and must contain a technically sound means to achieve this goal. Although any person may propose a
topic for a Reliability Standard to the ERO, in the ERO’s process, the specific proposed Reliability
Standard should be developed initially by persons within the electric power industry and community with a
high level of technical expertise and be based on sound technical and engineering criteria. It should be
based on actual data and lessons learned from past operating incidents, where appropriate. The process for
ERO approval of a proposed Reliability Standard should be fair and open to all interested persons.

regulators with established criteria that must be met in order to plan for the use of the
Footnote. The Footnote establishes, for U.S.-registered entities, quantitative limits on the
maximum amounts of load that can be shed, with the limits derived from the results of
the Data Request (the results of which can be found in Exhibit F). The result is a
consistent, documented process with firm limitations on use of the Footnote. The
technical analysis justifying the use of the Footnote in specific circumstances will be
available to all affected stakeholders in an open forum where all alternatives can be
discussed and resolved. ERO oversight will assure that there are no Adverse Reliability
Impacts on the Bulk Electric System from the planned actions.
2.

Proposed Reliability Standards must be applicable only to users, owners and
operators of the Bulk-Power System, and must be clear and unambiguous as
to what is required and who is required to comply. 4
The proposed Footnote is applicable to Planning Coordinators and Transmission

Planners. Planning Coordinators and Transmission Planners are users, owners, or
operators of the Bulk Electric System. The proposed Footnote achieves the stated
reliability goal of clearly stating what is required and who is required to comply.
Attachment 1 to the Footnote details the process that is to be followed, the information
requirements to justify the proposed application of the Footnote, and the timing involved
in the process steps. The standard states who the applicable entities are, and Attachment
1 reiterates the roles and responsibilities of the responsible entities at each step.

4

Id. at P 322. The proposed Reliability Standard may impose a requirement on any user, owner,
or operator of such facilities, but not on others.
Id. at P 325. The proposed Reliability Standard should be clear and unambiguous regarding
what is required and who is required to comply. Users, owners, and operators of the Bulk-Power System
must know what they are required to do to maintain reliability.

3.

A proposed Reliability Standard must include clear and understandable
consequences and a range of penalties (monetary and/or non-monetary) for a
violation. 5
Each primary requirement is assigned a VRF and a VSL. These elements support

the determination of an initial value range for the Base Penalty Amount regarding
violations of requirements in FERC-approved Reliability Standards, as defined in the
ERO Sanction Guidelines. The Consolidated TPL Standard does not modify the
proposed VRFs and VSLs that were included in the petition with the Commission for
approval on October 19, 2011. None of the previously approved VRFs and VSLs for the
Individual TPL Standards have been altered or changed in any way.
4.

A proposed Reliability Standard must identify clear and objective criterion
or measure for compliance, so that it can be enforced in a consistent and nonpreferential manner. 6
The proposed Footnote is clear in identifying the required performance and the

responsible entity. The proposed Footnote identifies clear and objective criteria so that
that the Footnote can be enforced in a consistent and non-preferential manner. The
Footnote is unambiguous with respect to the expectations of applicable entities. The
proposed Footnote establishes definitive steps that must be followed as well as clear,
quantitative criteria for planned use of the Footnote.

5

Id. at P 326. The possible consequences, including range of possible penalties, for violating a
proposed Reliability Standard should be clear and understandable by those who must comply.
6
Id. 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 nonpreferential manner.

5.

Proposed Reliability Standards should achieve a reliability goal effectively
and efficiently — but do not necessarily have to reflect “best practices”
without regard to implementation cost or historical regional infrastructure
design. 7
The proposed Footnote helps the industry achieve the goal of effective and

efficient system planning, while taking into account factors such as implementation, cost,
and geographic differences and system design. The stakeholder process outlined in
Attachment 1 provides that responsible planning entities must show the alternatives that
were considered in order to avoid potential problems, and provide the rationale for the
alternative selected. Factors such as implementation cost and unique system
characteristics would be taken into account and the planning entity can demonstrate to
stakeholders why a particular solution is being proposed. Thus, an entity can
appropriately weigh all the relevant factors and make them clear in an open and
transparent forum.

7

Id. at P 328. The proposed Reliability Standard does not necessarily have to reflect the optimal
method, or “best practice,” for achieving its reliability goal without regard to implementation cost or
historical regional infrastructure design. It should however achieve its reliability goal effectively and
efficiently.

6.

Proposed Reliability Standards cannot be “lowest common denominator,”
i.e., cannot reflect a compromise that does not adequately protect Bulk
Electric System reliability. Proposed Reliability Standards can consider
costs to implement for smaller entities, but not at consequences of less than
excellence in operating system reliability. 8
The proposed Footnote does not aim at the “lowest common denominator.” The

Footnote applies equally to all Planning Coordinators and Transmission Planners, without
differentiation based on size or cost. The quantitative criteria proposed in the Footnote
are derived from the results of the Data Request and set out reasonable, technically-sound
limits that define how a planning entity may plan to shed non-consequential load in a
single Contingency situation. The proposed limits cover variables that were not specified
in the Current TPL Standards and represent new and significant constraints for planning
entities.

8

Id. at P 329. The proposed Reliability Standard must not simply reflect a compromise in the
ERO’s Reliability Standard development process based on the least effective North American practice —
the so-called “lowest common denominator” — if such practice does not adequately protect Bulk-Power
System reliability. Although FERC will give due weight to the technical expertise of the ERO, we will not
hesitate to remand a proposed Reliability Standard if we are convinced it is not adequate to protect
reliability.
Order No. 672 at P 330. A proposed Reliability Standard may take into account the size of the
entity that must comply with the Reliability Standard and the cost to those entities of implementing the
proposed Reliability Standard. However, the ERO should not propose a “lowest common denominator”
Reliability Standard that would achieve less than excellence in operating system reliability solely to protect
against reasonable expenses for supporting this vital national infrastructure. For example, a small owner or
operator of the Bulk-Power System must bear the cost of complying with each Reliability Standard that
applies to it.

7.

Proposed Reliability Standards must be designed to apply throughout North
America to the maximum extent achievable with a single Reliability
Standard while not favoring one geographic area or regional model. It
should take into account regional variations in the organization and
corporate structures of transmission owners and operators, variations in
generation fuel type and ownership patterns, and regional variations in
market design if these affect the proposed Reliability Standard. 9
The requirements in the proposed Footnote apply throughout North America, with

an exception for non-U.S. registered entities. The Footnote allows for the amount of
planned non-consequential load loss for a non-U.S. registered entity to be implemented in
a manner that is consistent with, or under the direction of, the applicable governmental
authority or its agency in the non-U.S. jurisdiction. This “non-U.S.” exception is
warranted, because the limitations on the amount of load that can be planned to be shed
under the Footnote are, by legislation, the sole province of the local regulatory authorities
in those countries.
8.

Proposed Reliability Standards should cause no undue negative effect on
competition or restriction of the grid beyond any restriction necessary for
reliability. 10
The proposed Footnote enhances the operation and reliability of the BES, without

constraint on competition or transmission capability. The Footnote does not differentiate
9

Id. at P 331. A proposed Reliability Standard should be designed to apply throughout the
interconnected North American Bulk-Power System, to the maximum extent this is achievable with a single
Reliability Standard. The proposed Reliability Standard should not be based on a single geographic or
regional model but should take into account geographic variations in grid characteristics, terrain, weather,
and other such factors; it should also take into account regional variations in the organizational and
corporate structures of transmission owners and operators, variations in generation fuel type and ownership
patterns, and regional variations in market design if these affect the proposed Reliability Standard.
10
Id. at P 332. As directed by section 215 of the FPA, FERC itself will give special attention to
the effect of a proposed Reliability Standard on competition. The ERO should attempt to develop a
proposed Reliability Standard that has no undue negative effect on competition. Among other possible
considerations, a proposed Reliability Standard should not unreasonably restrict available transmission
capability on the Bulk-Power System beyond any restriction necessary for reliability and should not limit
use of the Bulk-Power System in an unduly preferential manner. It should not create an undue advantage
for one competitor over another.

among entities, and applies equally to all Planning Coordinators and Transmission
Planners. The Footnote presents a consistent approach to be followed across the North
American continent with appropriate emphasis on reliability.
9.

The implementation time for the proposed Reliability Standard is
reasonable. 11
The proposed Implementation Plans are reasonable and unchanged from proposed

Implementation Plans submitted previously to the Commission. The Implementation
Plans weigh carefully the significant nature of new requirements against the need for
responsible entities to gear up to meet those requirements. Accordingly, the proposed
effective dates represent a reasonable time frame to allow all entities to adequately
prepare for compliance with the new, more stringent requirements.

10.

The Reliability Standard was developed in an open and fair manner and in
accordance with the Commission-approved Reliability Standard
development process. 12
The Footnote and the Proposed TPL Standards were developed in accordance

with NERC’s Commission-approved, ANSI-accredited processes for developing and
approving Reliability Standards. As more fully described in Section IV of the petition

11

Id. at P 333. 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.
12
Id. at P 334 (“Further, in considering whether a proposed Reliability Standard meets the legal
standard of review, we will entertain comments about whether the ERO implemented its Commissionapproved Reliability Standard development process for the development of the particular proposed
Reliability Standard in a proper manner, especially whether the process was open and fair. However, we
caution that we will not be sympathetic to arguments by interested parties that choose, for whatever reason,
not to participate in the ERO’s Reliability Standard development process if it is conducted in good faith in
accordance with the procedures approved by FERC.”).

(Summary of the Reliability Standard Development Proceedings) and Exhibit G
(Summary of Proposed TPL Standards Development Authorization, Posting, and
Balloting History), these processes included, among other things, multiple comment; preballot review; and balloting periods, conducted pursuant to an aggressive schedule that
spanned a period of nearly seven months. All Drafting Team meetings were properly
noticed and open to the public. Stakeholders were involved during the comment periods.
The initial and recirculation ballots achieved the required quorum and ballot pool
thresholds. Specific details concerning these processes, including a complete
development history and a record of all stakeholder comments received, have been
included as Exhibit I.

11.

NERC must explain any balancing of vital public interests in the
development of proposed Reliability Standards.13
NERC has identified no competing public interests regarding the request for

approval of the Footnote and Proposed TPL Standards. No comments were received that
indicated that the Footnote or Proposed TPL Standards conflict with other vital public
interests.

13

Id. at P 335. Finally, we understand that at times development of a proposed Reliability
Standard may require that a particular reliability goal must be balanced against other vital public interests,
such as environmental, social and other goals. We expect the ERO to explain any such balancing in its
application for approval of a proposed Reliability Standard.

12.

Proposed Reliability Standards must consider any other appropriate
factors. 14
No other factors for FERC’s consideration were identified in the development of

the proposed Footnote.

13.

Proposed Reliability Standard must not conflict with prior FERC Rules or
Orders.
The Footnote and Proposed TPL Standards do not conflict with prior Commission

Rules or Orders. To the contrary, they respond to Commission concerns most recently
articulated in Order No. 762 and the TPL NOPR.

14

Id. at P 337. In considering whether a proposed Reliability Standard is just and reasonable, the
Commission may consider any other factors it deems appropriate for determining if the proposed
Reliability Standard is just and reasonable, not unduly discriminatory or preferential, and in the public
interest. The ERO may, if it chooses, propose other such general factors in its application and may propose
additional specific factors for consideration with a particular proposed Reliability Standard.

Exhibit F
Results of Section 1600 Data Request

Proposed Request for Data or Information
Order No. 762 Transmission System Performance Following
Loss of a Single Bulk Electric System Element
NERC posted the proposed data request in accordance with the requirements of Section 1606 of the
NERC Rules of Procedure for public comment. The twenty-one (21) day comment period ran from June
19 through July 9, 2012. NERC provided this proposed data request to FERC for information on May 23,
2012, as required by Section 1602 of the NERC Rules of Procedure. NERC presented this proposed data
request, revised as appropriate in light of the comments received, to the NERC Board of Trustees for
approval, as required by Section 1602 of the NERC Rules of Procedure on July 26, 2012. The NERC
Board of Trustees approved the revised data request and it has now been issued and has become
mandatory.
The purpose of this data request is to solicit data and information from each registered Transmission
Planner in the United States and Canada 1 in order to provide information identifying the specific
instances of any planned interruptions of Firm Demand under footnote b and how frequently the
provision has been used. This data will be used by the Standards Drafting Team to guide its
deliberations in areas where threshold values are suggested in the revised footnote b. NERC will also
share the data received in response to this data request with FERC.
The data request was posted publicly for 30 days, from July 31, 2012 through August 30, 2012.
Transmission Planners were asked to provide data or information through a special electronic
comment form. There were 158 responses submitted, with some responses representing multiple
entities, representing 7 of the 10 Industry Segments as shown in the table on the following pages.
All data requests and information submitted may be reviewed in their original format on the standard’s
project page.
If you feel that your submitted data has been overlooked, please let us know immediately. If you feel
there has been an error or omission, you can contact the Vice President and Director of Standards,
Mark Lauby, at 404-446-2560 or at [email protected]. In addition, there is a NERC Reliability
Standards Appeals Process. 2

1

In the United States responding to this data request is mandatory. NERC strongly encourages Canadian entities to respond
to this data request to ensure the completeness of the data collected.

2

The appeals process is in the Standard Processes Manual:
http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Index to Questions, Comments, and Responses

1.

For which NERC Compliance Registry (NCR) numbers are you completing this Data Request? ...... 11

2.

Does the Planning Assessment for the interconnected transmission system for which you have
planning responsibility include any instances of planned interruption of Firm Demand to address
BES performance requirements following a single contingency (i.e., any use of “planned or
controlled interruption of supply”) as described in footnote “b” of the TPL-002-0b Reliability
Standard for the last 3 completed Planning Assessments? ..................................................... 22

3a. If the answer to Question 2 is yes, please identify: ............................................................... 23
3b. Each unique instance within the applicable Planning Assessment in which planned interruption of
Firm Demand has been used as a strategy to address BES performance requirements following a
single contingency, including the size (in MW) of the planned interruption of Firm Demand, and
the operating voltage level (kV) and description of each contingency.Error! Bookmark not defined.
3c. The size (in MW) of the each instance of planned interruption of Firm Demand following a single
contingency within the applicable Planning Assessment. ............. Error! Bookmark not defined.
3d. The estimated cost (if known) of reinforcements needed to eliminate the need for each instance of
planned interruption of Firm Demand in the applicable Planning Assessment following a single
contingency. ....................................................................... Error! Bookmark not defined.
3e. The year (if known) in which reinforcements are planned to eliminate the need for each instance
of planned interruption of Firm Demand in the applicable Planning Assessment following a single
contingency. ....................................................................... Error! Bookmark not defined.

3f. What year was the earliest instance of planned interruption of Firm Demand following a single
contingency that is still included in the applicable Planning Assessment identified?Error! Bookmark not def

3g. What year was the most recent instance of planned interruption of Firm Demand following a single
contingency that is still included in the applicable Planning Assessment identified?Error! Bookmark not def

Consideration of Comments: Proposed Request for Data or Information Order No. 762

2

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

1.

Group

Chris Higgins

Bonneville Power Administration

X

X

2.

Group

Sammy Alcaraz

Imperial Irrigation District (IID)

X

X

3.

Group

Jennifer Eckels

Colorado Springs Utilities

X

X

4.

Group

Sunitha Kothapalli

Puget Sound Energy

X

5.

Group

Jason Shook

East Texas Electric Cooperative, Inc.

X

X

6.

Group

Delyn Kilpack

LG&E and KU Services

X

X

X

7.

Individual

Terry Torgerson

Dairyland Power Cooperative

X

X

X

8.

Individual

JANET SMITH

ARIZONA PUBLIC SERVICE COMPANY

X

X

X

X

9.

Individual

Antonio Grayson

Southern Company

X

X

X

X

10.

Individual

Lonnie Lindekugel

Southwest Power Pool RTO

X

X

X

X

X

X

X

X

X

X
X

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

Individual

Tim Ponseti, VP

TVA Transmission Reliability Engineering &
Controls

Individual

Renee Davidson

South Texas Electric Cooperative, Inc.

Individual
14. Individual

Brian Whalen
Brian Whalen

Nevada Power Company - NCR05261
Sierra Pacific Power Company - NCR05390

X
X

X
X

15.

Terry Harbour

MidAmerican Energy

X
X

X
X

X

X
X

11.
12.
13.

16.

Individual

John Burnett

18.

Individual

Theresa Allard

Minnkota Power Cooperative, Inc.

X

19.

Individual

Aaron Staley

City of Vero Beach

X

20.

Individual

Bryant D. Williamson

Memphis Light, Gas and Water

X

21.

Individual

Richard Bachmeier

Gainesville Regional Utilities

X

X

22.

Individual

Michael Jones

National Grid

X

X

23.

Individual

William Berry
(CHPD) Public Utility
District No. 1 of Chelan
County

OMU

CenterPoint Energy Houston Electric, LLC

Individual

Daniela Hammons
Raymond Andrew
Foster

Nashville Electric Service

27.

Individual

Scott Bos

Muscatine Power and Water

28.

Individual

Gini Ingram

Lafayette Utilities System

Individual
30. Individual

Lou Magyar
Eric Olson

Hoosier Energy REC, Inc.
Transmission Agency of Northern California

X

31.

Individual

D Roberts

SBEC

32.

Individual

Scott Waples

Avista Corporation

X
X

Individual
25.
26.

Individual

29.

6

7

8

9

X

Individual

24.

Esteban Martinez

5

X

Turlock Irrigation District
Los Angeles Department of Water and
Power

17.

Individual

4

X
X
X

X
X

X
X

X

X

X

X
X

X

X

X

X

X

X

X

X

X

Public Utility District No. 1 of Chelan County
(CHPD)
X
X
X

X
X

X

Consideration of Comments: Proposed Request for Data or Information Order No. 762

X
X

4

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

33.

Individual

Joe Tarantino

Sacramento Municipal Utility District

X

34.

Individual

Southwestern Power Administration

X

Individual
36. Individual

Tracey Stewart
Western Area Power
Administration
Richard E Biggerstaff

37.

Individual

Greg Keller

Florida Power & Light

38.

Individual

Angela P Gaines

Portland General Electric Company

39.

Individual

Jose H Escamilla

35.

2

3

X

4

X

5

X

X

X

X
X

X
X

X
X

X

X

X

X

X

X

X

X

Individual

Laurie Williams

42.

Individual

Rakesh Sharma

JEA

X

43.

Individual

Tony Gott

X

X

Individual

Arun Sethi

Associated Electric Cooperative, Inc.
Western Area Power Administration - Sierra
Nevada Region

45.

Individual

Shari Heino

Brazos Electric Power Cooperative, Inc.

X

X

46.

Individual

John Pearson

ISO New England

47.

Individual

Bob Easton

X
X

X
X

X

Individual

Patrick Harwood

49.

Individual

Andrew Gallo

City of Austin dba Austin Energy

X

50.

Individual

Jonathan Appelbaum

The United Illuminating Company

X

Individual
52. Individual

Thomas E King Jr
Larry Watt

Wolverine Power Supply Cooperative, Inc
Lakeland Electric

X

X

X

X

53.

Individual

Paul Haase

Seattle City Light

X

54.

Individual

Wryan J. Feil

Northeast Utilities

X
X

51.

X

X
X

X

X

X

WAPA-RMR
Western Area Power Administration Desert
Southwest Region

48.

9

X

Rob Collins

44.

8

Upper Great Plains Region
Sharyland Utilities, L.P.

Individual
41.

7

X

CPS Energy
Southern Indiana Gas & Electric Company
d/b/a Vectren Energy Delivery of Indiana
Inc.
Public Service Company of New Mexico
(PNM)

40.

6

Consideration of Comments: Proposed Request for Data or Information Order No. 762

X

X

X

X

X

X

X

X

5

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

X

Franklin Lu

Public Utility District No. 1 of Snohomish
County

X

Individual
Individual

Will Franklin

Public Service Company of Colorado

X

Individual
58. Individual

Jonathan Fidrych
Edward O'Brien

Tri-State G & T Association, Inc.
Modesto Irrigation District

X

59.

Individual

Kevin Lyons

Central Iowa Power Cooperative

60.

Individual

John Allen

City Utilities of Springfield, MO

X

61.

Individual

Randi Nyholm

Minnesota Power

X

62.

Individual

Keith Morisette

Tacoma Power

X

X

63.

Individual

Tiffany Lake

Westar Energy, Inc.

X

X

64.

Individual

Michael Haff

Seminole Electric Cooperative, Inc.

65.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

X

66.

Individual

Gary Trent

Tucson Electric Power Company

X

67.

Individual

Darrin Adams

East Kentucky Power Cooperative

X

68.

Individual

Greg Keller

Lone Star Transmission, LLC

X

69.

Individual

Greg Keller

Horse Hollow Generation Tie, LLC.

X

70.

Individual

Kirit Shah

Ameren

X

71.

Individual

Martyn Turner

LCRA Transmission Services Corporation

X

72.

Individual

James Tucker

Deseret Power

73.

Individual

Debbie Manning

74.

Individual

75.

55.
56.
57.

4

6

X

X

X

X

X

X

X

X

X

5

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

Bangor Hydro Electric Company

X

X

Terri Pyle

Oklahoma Gas & Electric

X

X

X

Individual

Andrew Z. Pusztai

American Transmission Company

76.

Individual

Harold Wyble

Kansas City Power & Light

X
X

X

X

77.

Individual

Jennifer Wright

San Diego Gas & Electric
Southwestern Public Service Co, an Xcel
Energy company

X

X

X

X

X

X

78.

Individual

Alice Ireland

X

Consideration of Comments: Proposed Request for Data or Information Order No. 762

7

X
X

X

X
X

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

Greg Rowland

Duke Energy

X

X

X

X

Individual
81. Individual

Michelle Corley
Joe Knight

Cleco Corporation
Great River Energy

X

X

X

X

X

X

X

X

82.

Individual

Frank Gaffney

Florida Municipal Power Agency

X

83.

Individual

Jim Kelley

PowerSouth Energy Cooperative

X

X
X

84.

Individual

Donald Bauer

NorthWestern Corporation

X

X

X

85.

Individual

chris diebold

city of tallahassee

X

X

X

86.

Individual

James Peterson

South Carolina Public Service Authority

X

X

X

87.

Individual

Milorad Papic

Idaho Power Co.

X

X

88.

Individual

Gregory Campoli

New York Independent System Operator

89.

Individual

Jeremy Brownrigg

Platte River Power Authority

X

90.

Individual

Jan Horbaczewski

Texas Municipal Power Agency

X

91.

Individual

Shawndra Green

Bryan Texas Utilities

92.

Individual

Thad Ness

Individual

94.

79.

Individual

80.

X

X

8

9

X
X

X

X

X

X

X

X

X

X

X

David A Macey

American Electric Power
City of Independence Department of Power
& Light

Individual

Brad Hofferkamp

PJM

X

95.

Individual

Don Schmit

Nebraska Public Power District

96.

Individual

Bob Case

Black Hills Corporation

X

97.

Individual

Ruth Kloecker

ITC Holdings

X

98.

Individual

Raiza Calderon

Tampa Electric Company

X

99.

Individual

Boris Tumarin

Southwest Transmission Cooperatives, inc

100. Individual

Chris Bradley

Big Rivers Electric Corporation

X
X

X

101. Individual

Alan Wilson

SMEPA

X

X

102. Individual

Oliver Burke

Entergy Services, Inc.

X

103. Individual

Eric Ruskamp

Lincoln Electric System

X

93.

7

X

Consideration of Comments: Proposed Request for Data or Information Order No. 762

X
X

X

X
X

X

X

X
X
X

X

X

X

X

X

X

X

X
7

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

104. Individual

Marco Rios

Pacific Gas and Electric Company

X

X

X

105. Individual

Jeff Jones
David Rudolph

X

X

X

X

X

X

X

X

X

X

Keira Kazmerski

Southern Illinois Power Cooperative
Basin Electric Power Cooperative (BEPC)
Northern States Power Company, an Xcel
Energy company

108. Individual

Brenton Lopez

Salt River Project

X

David Baker

Bandera Electric Cooperative, Inc.

X
X

X

109. Individual

X
X

110. Individual

Sunflower Electric Power Corporation
El Paso Electric Co.

X

X

111. Individual

Lindsay Shepard
Pablo Onate

112. Individual

Dean Ahlsten

Eugene Water & Electric Board

106. Individual
107.

Individual

113. Individual
114. Individual

Gerry Nunan

115. Individual

DeWayne Todd

116. Individual

David Grubbs

117. Individual

Mike Pullen

118. Individual

Galen Gillum

119. Individual

Tyler Baxter

120. Individual

Stacey Englemann

121. Individual

Tim Lyons

122. Individual

John Delucca

123. Individual

Mike Stafford

124. Individual
125. Individual

Frank Owens
Steve Rose

126. Individual

Julius Horvath

127. Individual

Sandra Shaffer

128. Individual

Nathan McNeil

7

X
X

GCPUD
Bluebonnet Electric Cooperative
Alcoa Power Generating Co.
City of Garland
Electric Energy Inc.
City of Denton
Corn Belt Power
City of College Station
Owensboro Municipal
Lee County
Grand River Dam Authority
Cross Texas Transmission
City Water Light & Power
Wind Energy of Texas
Pacificorp
Midwest Energy

Consideration of Comments: Proposed Request for Data or Information Order No. 762

8

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

129. Individual

Archie Lopez

130. Individual

Mike Holtsclaw

131. Individual

Rick Luckadoo

132. Individual
133. Individual

Greg Baumbach
Caitlin Hojnacki

134. Individual

Zandalio Martinez

135. Individual

Joseph Turano

136. Individual

Joseph Turano

137. Individual

Kim Moulton

138. Individual

John Robertson

139. Individual

Amanda Underwood

140. Individual

Daryll Curtis

141. Individual

Lee Kittelson

142. Individual

Rich Dragonajtys

143. Individual

Nathan Smith

144. Individual

Caleb Muckala

145. Individual

Rich Koch

146. Individual

David Rusley

147. Individual

Ron Wyble

148. Individual

Bob Mattey

149. Individual
150. Individual

Rex McDaniel
Nelson Nease

151. Individual

Bob Adam

152. Individual

Dennis Minton

153. Individual

Jason Snodgrass

154. Individual

Hank LuBean

2

3

4

5

6

7

Pedernales Electric Co-op
Indianapolis Power & Light
Rochester Public Utilities
New Braunfels Utilities
City of Lansing
Brownsville PUB
Central Maine
Maine Electric
Vermont Transco
NSTAR
Omaha PPD
Oncor
Otter Tail Power
Merced Irrigation District
SCE
Western Farmers
Southern Minnesota
Cedar Falls
Columbia Water & Light
Ohio Valley
Texas New Mexico
Guadeloupe Valley
Kansas City BPU
Florida Keys
GTC
Douglas County PUD

Consideration of Comments: Proposed Request for Data or Information Order No. 762

9

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

155. Individual

Fred Meyer

156. Individual

Aaron Staley

157. Individual

Robert Fox

158. Individual

Aaron Staley

2

3

4

5

6

Empire District
Orlando Utilities Commission
NIPSCO
Orlando PUC

Consideration of Comments: Proposed Request for Data or Information Order No. 762

10

7

8

9

10

1.

For which NERC Compliance Registry (NCR) numbers are you completing this Data Request?

Organization

Question 1 Comment

1. Tri-State G & T Association, Inc.

NCR10030

2. City of Tallahassee

NCR00073

3. Dairyland Power Cooperative

NCR00762

4. Wolverine Power Supply Cooperative, Inc

NCR00954

5. Lincoln Electric System

NCR01001

6. Nebraska Public Power District

NCR01018

7. City of Independence Department of Power & Light

NCR01072

8. Southwest Power Pool RTO

NCR01143

9. TVA Transmission Reliability Engineering & Controls

NCR01151

10. East Kentucky Power Cooperative

NCR01225

11. OMU

NCR01290

12. Bryan Texas Utilities

NCR04022

13. SBEC

NCR04118

14. Sharyland Utilities, L.P.

NCR04119

Consideration of Comments: Proposed Request for Data or Information Order No. 762

11

Organization

Question 1 Comment

15. Colorado Springs Utilities

NCR05106

16. Public Utility District No. 1 of Chelan County (CHPD)

NCR05338

17. Western Area Power Administration Desert Southwest
Region

NCR05461

18. WAPA-RMR

NCR05464

19. Western Area Power Administration - Sierra Nevada
Region

NCR05465

20. Public Service Company of Colorado

NCR05521

21. The United Illuminating Company

NCR07222

22. South Carolina Electric and Gas

NCR00915

23. American Transmission Company

NCR #685

24. PowerSouth Energy Cooperative

NCR 10203

25. Florida Municipal Power Agency

NCR00022

26. Florida Power & Light

NCR00024

27. Gainesville Regional Utilities

NCR00032

28. JEA

NCR00040

Consideration of Comments: Proposed Request for Data or Information Order No. 762

12

Organization

Question 1 Comment

29. Lakeland Electric

NCR00044

30. Seminole Electric Cooperative, Inc.

NCR00068

31. Tampa Electric Company

NCR00074

32. City of Vero Beach

NCR00079

33. Basin Electric Power Cooperative (BEPC)

NCR00102, NCR05023

34. Westar Energy, Inc.

NCR00658

35. Minnesota Power

NCR00674

36. Hoosier Energy REC, Inc.

NCR00794

37. ITC Holdings

NCR00820, NCR00803, NCR10192, NCR10400

38. MidAmerican Energy

NCR00824

39. Southern Indiana Gas & Electric Company d/b/a
Vectren Energy Delivery of Indiana Inc.

NCR00917

40. Muscatine Power and Water

NCR00967

41. Central Iowa Power Cooperative

NCR00970

42. Great River Energy

NCR00992

43. Minnkota Power Cooperative, Inc.

NCR01013

Consideration of Comments: Proposed Request for Data or Information Order No. 762

13

Organization

Question 1 Comment

44. Northern States Power Company, an Xcel Energy
company

NCR01020 (Northern States Power Company)

45. Upper Great Plains Region

NCR01036 & NCR05467

46. American Electric Power

NCR01056, NCR04006, NCR10211

47. Kansas City Power & Light

NCR01058 NCR01107

48. City Utilities of Springfield, MO

NCR01081

49. Cleco Corporation

NCR01083

50. Lafayette Utilities System

NCR01114

51. Oklahoma Gas & Electric

NCR01130

52. Southwestern Power Administration

NCR01144

53. Southwestern Public Service Co, an Xcel Energy
company

NCR01145

54. Sunflower Electric Power Corporation

NCR01148

55. Ameren

NCR01175

56. Associated Electric Cooperative, Inc.

NCR01177

57. Big Rivers Electric Corporation

NCR01180

Consideration of Comments: Proposed Request for Data or Information Order No. 762

14

Organization

Question 1 Comment

58. Entergy Services, Inc.

NCR01234

59. Duke Energy

NCR01298, NCR00761, NCR01219 and NCR00063

60. East Texas Electric Cooperative, Inc.

NCR01307, NCR01227, NCR01124, NCR01342

61. South Carolina Public Service Authority

NCR01312

62. SMEPA

NCR01315

63. Southern Company

NCR01320, NCR01278

64. Southern Illinois Power Cooperative

NCR01321

65. PJM

NCR02602,NCR00682,NCR00686,NCR00688,NCR00689,NCR00712,NCR0801
3,NCR00752,NCR00761,NCR00762,NCR00251,NCR00806,NCR10376,NCR00
821,NCR00130,NCR08026,NCR00872,

66. Bandera Electric Cooperative, Inc.

NCR04008

67. Brazos Electric Power Cooperative, Inc.

NCR04015

68. CenterPoint Energy Houston Electric, LLC

NCR04028

69. City of Austin dba Austin Energy

NCR04029

70. CPS Energy

NCR04037

71. LCRA Transmission Services Corporation

NCR04091

Consideration of Comments: Proposed Request for Data or Information Order No. 762

15

Organization

Question 1 Comment

72. South Texas Electric Cooperative, Inc.

NCR04124

73. Texas Municipal Power Agency

NCR-04141

74. ARIZONA PUBLIC SERVICE COMPANY

NCR05016

75. Black Hills Corporation

NCR05030 and NCR00089

76. Bonneville Power Administration

NCR05032

77. Tacoma Power

NCR05097

78. Deseret Power

NCR05126,NCR05127

79. Idaho Power Co.

NCR05191

80. Imperial Irrigation District (IID)

NCR05195

81. Avista Corporation

NCR0520

82. Los Angeles Department of Water and Power

NCR05223

83. Modesto Irrigation District

NCR05244

84. Nevada Power Company - NCR05261

NCR05261

85. NorthWestern Corporation

NCR05282

86. Pacific Gas and Electric Company

NCR05299

Consideration of Comments: Proposed Request for Data or Information Order No. 762

16

Organization

Question 1 Comment

87. Platte River Power Authority

NCR05321

88. Portland General Electric Company

NCR05325

89. Public Service Company of New Mexico (PNM)

NCR05333

90. Public Utility District No. 1 of Snohomish County

NCR05335

91. Puget Sound Energy

NCR05344

92. Sacramento Municipal Utility District

NCR05368

93. Salt River Project

NCR05372

94. San Diego Gas & Electric

NCR05377

95. Seattle City Light

NCR05382

96. Sierra Pacific Power Company - NCR05390

NCR05390

97. Southwest Transmission Cooperatives, inc

NCR05402

98. Transmission Agency of Northern California

NCR05430

99. Tucson Electric Power Company

NCR05434

100. Turlock Irrigation District

NCR05435

101. Bangor Hydro Electric Company

NCR07013

Consideration of Comments: Proposed Request for Data or Information Order No. 762

17

Organization

Question 1 Comment

102. ISO New England

NCR07124

103. New York Independent System Operator

NCR07160

104. Northeast Utilities

NCR07176

105. Horse Hollow Generation Tie, LLC.

NCR10392

106. Lone Star Transmission, LLC

NCR11076

107. Nashville Electric Service

NCR11077

108. National Grid

NCR11171 National Grid USA

109.

LG&E and KU Services

NRC01223

110.

Memphis Light, Gas and Water

NCR11066

111.

El Paso Electric Company

NCR05140

112.

GCPUD

NCR05342

113. Eugene Water & Electric Board

NCR05153

114. Bluebonnet Electric Cooperative

NCR0413

115.

NCR01168 & NCR01169

Alcoa Power Generating Co.

116. City of Garland

NCR04033

117. Electric Energy Inc.

NCR01230

Consideration of Comments: Proposed Request for Data or Information Order No. 762

18

Organization

Question 1 Comment

118. Wind Energy of Texas

NCR11074

119. City of Denton

NCR04049

120. Corn Belt Power

NCR00977

121. City of College Station

NCR04032

122. Owensboro Municipal

NCR01290

123. Lee County

NCR00045

124. Grand River Dam Authority

NCR01101

125. Cross Texas Transmission

NCR11114

126. City Water Light & Power

NCR01328

127. Pacificorp

NCR05304

128. Midwest Energy

NCR01118

129. Pedernales Electric Co-op

NCR04111

130. Indianapolis Power & Light

NCR00798

131. Rochester Public Utilities

NCR01027

132. New Braunfels Utilities

NCR04101

133. City of Lansing

NCR00718

134. Brownsville PUB

NCR04018

Consideration of Comments: Proposed Request for Data or Information Order No. 762

19

Organization

Question 1 Comment

135. Central Maine

NCR07029

136. Maine Electric

NCR07134

137. Vermont Transco

NCR07228

138. NSTAR

NCR07180

139. Omaha PPD

NCR00860

140. Oncor

NCR04109

141. New Brunswick

NCR10024

142. Otter Tail Power

NCR01023

143. Merced Irrigation District

NCR05234

144. SCE

NCR05398

145. Western Farmers

NCR 01160

146. Southern Minnesota

NCR01030

147. Cedar Falls

NCR00969

148. Columbia Water & Light

NCR 01196

149. Ohio Valley

NCR00857

150. Texas New Mexico

NCR04143

151. Guadalupe Valley

NCR04079

Consideration of Comments: Proposed Request for Data or Information Order No. 762

20

Organization

Question 1 Comment

152. Kansas City BPU

NCR01061

153. Florida Keys

NCR00021

154. GTC

NCR01249

155. Douglas County PUD

NCR05343

156. Empire District

NCR01155

157. Orlando Utilities

NCR00057

158. NIPSCO

NCR02611

Consideration of Comments: Proposed Request for Data or Information Order No. 762

21

2.

Does the Planning Assessment for the interconnected transmission system for which you have planning responsibility include
any instances of planned interruption of Firm Demand to address BES performance requirements following a single contingency
(i.e., any use of “planned or controlled interruption of supply”) as described in footnote “b” of the TPL-002-0b Reliability
Standard for the last 3 completed Planning Assessments?

Summary Consideration: The overwhelming majority of respondents do not utilize footnote ‘b’ in their planning process. There were
only 18 entities indicating any utilization of footnote ‘b’ in their planning process.
Table removed for reasons of confidentiality.

Consideration of Comments: Proposed Request for Data or Information Order No. 762

22

3.

If the answer to Question 2 is yes, please identify:
a. Indicate the year of the Planning Assessment for which you are reporting.
b. Each unique instance within the applicable Planning Assessment in which planned interruption of Firm Demand has been
used as a strategy to address BES performance requirements following a single contingency, including the size (in MW) of
the planned interruption of Firm Demand, and the operating voltage level (kV) and description of each contingency.
c. The size (in MW) of the each instance of planned interruption of Firm Demand following a single contingency within the
applicable Planning Assessment.
d. The estimated cost (if known) of reinforcements needed to eliminate the need for each instance of planned interruption of
Firm Demand in the applicable Planning Assessment following a single contingency.
e. The year (if known) in which reinforcements are planned to eliminate the need for each instance of planned interruption of
Firm Demand in the applicable Planning Assessment following a single contingency.
f. What year was the earliest instance of planned interruption of Firm Demand following a single contingency that is still
included in the applicable Planning Assessment identified?
g. What year was the most recent instance of planned interruption of Firm Demand following a single contingency that is still
included in the applicable Planning Assessment identified?

Organization
A

Question 3a Comment
a. 2011
b. In 2013 winter season:
I) 8.4 MW, 230 kV, Contingency 230 kV;
II) 8.4 MW, 230 kV, Contingency transformer 230/138 kV;
III) 43 MW, 230 kV, Contingency 230 kV;
IV) 14 MW, 115 kV, Contingency 115 kV.
c. See answer b.
d. Unknown

Consideration of Comments: Proposed Request for Data or Information Order No. 762

23

Organization

Question 3a Comment
e. Unknown
f. 2013 Winter case - In 2011 Assessment
g. same as answer to f

B

a. 2011
b. Contingency: Loss of the 230 kV line. The size of the planned interruption of Firm
Demand is determined by the amount of load above 65 MW. Operating voltage
level: 115 kV.
c. The size of planned interruption of Firm Demand is determined by the size of the
load during the time of the contingency. For loss of the 230 kV line, load is limited
to 65 MW. (This represents a 69 MW load drop.)
d. Unknown
e. Unknown
f. 1998
g. 1998

C

a. 2011
b. The planned outage of certain 100 kV facilities in the area that feed a 50 kV
system including load can require a 10 - 12 MW curtailment of the load to avoid
low voltage problems on the area 100 and 50 kV systems. Unplanned outages
may cause the shedding of a similar amount of load through the customer's under
voltage relay protection, but voltages within tolerances result after the load shed.
Note: C has not intentionally chosen curtailment of firm demand as a form of
mitigation for system problems such as this.
c. Again, 10 - 12 MW
d. We are planning a new transmission line into this area, with associated substation
work. Estimated cost $M

Consideration of Comments: Proposed Request for Data or Information Order No. 762

24

Organization

Question 3a Comment
e.
f. 2006 (possibly earlier)
g.

D

a. 2012
b. 1. interruption of 2.5 MW, 161-kV, contingency of tap line section
2. interruption of 4.1 MW, 161-kV, contingency of
3. interruption of 4.3 MW, 161-kV, contingency of
c. See response to question 3b.
d. Each of the three events described in question 3b would minimally require a
capacitor bank at estimated cost of $. However another option for each of these
three contingencies could be a 7 mile (average of three events) transmission line
along with a 161-kV switching station. The total cost for including both line and
station costs could exceed $ million to fix each contingency.
e. 1.
2.
3.
f. 2010 (earliest of past 3 completed Planning Assessments)
g. 2012

E

a.
b. The 138 kV line has two tapped loads. The total load is about 30 MW. The
breakers are at. Thus whenever the line trips for a fault or other reason, the load
is interrupted. This design has been in place since it was constructed in 1985.
c. in all assessments about 30 MW
d. $ million, a second line would be required.

Consideration of Comments: Proposed Request for Data or Information Order No. 762

25

Organization

Question 3a Comment
e. Not currently planned
f. The line with the load taps was built in 1985 and has not been changed.
g. 2012

Comment: This data was not considered as the respondent provided data for tapped or Consequential Load.
F

a. 2009 and 2010
b. 2009 Assessment: #1.Loss of 138 kV;10 MW Planned Interruption of Firm Demand
(Summer, 20).
#2.Loss of 138 kV; 5 MW Planned Interruption of Firm Demand (Summer, 20).
#3 Loss of 230 kV;
(a) 30 MW Planned Interruption of Firm Demand (Winter),
(b) 25 MW Planned Interruption of Firm Demand (Summer),
(c) 40 MW Planned Interruption of Firm Demand (Winter).
#4.Loss of 138 kV; 10 MW Planned Interruption of Firm Demand (Summer).
2010 Assessment: #1.Loss of 138 kV;
(a) 20 MW Planned Interruption of Firm Demand (Winter).
(b) 25 MW Planned Interruption of Firm Demand (Winter).
c. 2009 Assessment: #1. 10 MW,
#2. 5 MW
#3. (a) 30 MW, (b) 25 MW, (c) 40 MW,
#4. 10 MW.
2010 Assessment: #1(a) 20 MW, (b) 25 MW.
d. 2009 Assessment: #4. $

Consideration of Comments: Proposed Request for Data or Information Order No. 762

26

Organization

Question 3a Comment
e. 2009 Assessment: #4. 2011
f. 2009 Assessment: #1. 20 Summer,
#2. 20 Summer,
#3. (a) 20 Winter, (b) 20 Summer, (c) 20 Winter,
#4. 20 Summer.
2010 Assessment: #1(a) 20 Winter, (b) 20 Winter.
g. See response above for 3f.

G

a. 2009, 2010, 2011
b. 30MW, 115kV, loss of 115kV line segment. Operating Guide is used to restore
load until project is completed in 20.
c. 30MW
d. $
e. 6/1/2013
f. 2009
g. 2011

H

a. 2009,2010, 2011
b. The 2009 Planning Assessment recommended undervoltage load shedding of firm
demand served from the 115 kV switching station following a single contingency.
The interruption of firm demand was implemented as an interim measure
pending completion of an additional transmission circuit. The area system had
recently been acquired. As acquired, the system was served by two 115 kV
transmission lines. The addition of a 3rd 115 kV transmission line and voltage
support were identified in previous Planning Assessments to bring the system in
the contingency performance criteria. The recommendation for undervoltage
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Question 3a Comment
load shedding was included in the 2009 Planning Assessment due to delays
experienced in completing the third transmission line. The contingency resulting
in voltage criteria violations was loss of the 115 kV line. The undervoltage load
shedding scheme had the potential to shed up to 26 MW depending on the load
level.
The 2010 Planning Assessment identified the need to extend undervoltage load
shedding in the area through 2011. The issues identified in the 2009 Planning
Assessment were aggravated by failure of a 345/115 kV transformer. However,
the 2010 Planning Assessment indicated that the replacement of the transformer
and completion of the 3rd 115 kV line would not mitigate the need to shed firm
load for a single contingency. Additional voltage support would be needed to
mitigate load shedding due to a single contingency. The amount of load subject to
undervoltage load shedding by the 2011 summer peak was 31 MW.
The 2011 Planning Assessment indentified the need to extend the undervoltage
load shedding in the area through 2011 due to a delay in installing additional
voltage support. The amount of load subject to undervoltage load shedding by
the 2012 summer peak remained at 31 MW.
c. The 2009 assessment identified up to 26 MW for 2010 summer peak forecast
area load.
The 2010 assessment identified up to 31 MW of the 2011 summer peak forecast
area load.
The 2011 assessment identified up to 31 MW of the 2012 summer peak forecast
area load.
d. The instance identified that impacted both the 2009 and 2010 assessments was
eliminated with the addition of third transmission line. Additional voltage
support is also required to eliminate the need for planned interruption at a

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Organization

Question 3a Comment
projected cost of $ million.
e. The third transmission line into the area and replacement of the transformer
were completed in 20. The required voltage support is planned to be installed in
20.
f. 2010
g. 2012

I

a. 2010 and 2011
b. The following are examples where used planned interruption of firm demand to
address BES performance requirements in previous planning studies. Note: When
I identifies a reliability issue in the outer years, it develops plans to mitigate the
issue and does not use load curtailment as sole long term mitigation to reliability
issues. However, in the near term, if reliability issues occur and cannot be
mitigated in a timely manner through system reinforcement, then Load
curtailment is exercised as a potential option to mitigate until a permanent
solution is developed and acted upon.
See tables at end of report for details.
c. Shown in previous tables.
d. Unknown
e. Example 1: 115 kV line contraction schedule to be completed by the end of .
Example 2: 115 kV line contraction schedule to be completed by the end of .
Example 3: 115 kV contraction schedule to be completed by the end of .
Example 4: 115 kV line contraction schedule to be completed by the end of .
f. 2012
g. 2012

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Question 3a Comment

J

a. 2010 Assessment
2011 and 2012 interim assessments.
b. J has two instances, in the transmission area, where footnote b of TPL-002-0b
could be considered to be addressing a performance requirement following a
single contingency. The interruption is only considered part of a temporary
mitigation plan until a project to address the situation is completed. The two
instances involve the overloading of either of two 115kV lines where 20MW is the
planned interruption of Firm Demand for each instance should the contingencies
occur during summer system peak conditions. It should be noted that the two,
115kV lines are radial lines that today are considered part of the BES. However,
in the future it is possible that these lines would be excluded from the BES based
on exclusion E1 in the proposed NERC BES 100 kV and up definition.
c. 20 MW of load for each of the two instances during summer system peak
conditions.
d. The total cost to re-conductor both transmission lines is estimated at $M. The
cost is estimated to be approximately split evenly for each of the two
transmission lines. Distribution transformation additions are also planned.
e. The present estimate for completion of the reinforcements is.
f. In the 2010 assessment, overload was seen in 2010 and the reinforcement project
was expected to be completed in 2011. However, the present estimate for
completion of the reinforcements is May 20.
g. Given the present status of in-service expectation for the line re-conductoring
project, there would continue to be interruption of demand if each contingency
were to occur during summer peak conditions in years 2012 & 2013.

K

a. 2010, 2011, 2012 Note: Yes. K does plan utilizing footnote b following a single

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Question 3a Comment

b.

c.

d.
e.
f.
g.

contingency. The footnote is applied in anticipation of the next outage.
Transmission system stays within both thermal and voltage limits post category B
contingencies.
The statistic of each unique instance is not tracked. There are a number of areas
on the transmission system where this can take place. Load Shedding or
generation re-dispatch as stated in footnote B can occur with a number of
variations on a group of outages.
K does not track unique instances of the quantity of load that needs to be shed to
mitigate category C3 load shedding associated with footnote B. K believes that
there are many combinations of contingencies that will require implementation
of footnote B. A few instances require more than 100 MW of load to be impacted
but less than 200 MW.
Not Known
Not known
Not known at this time
The draft 2012 assessment includes load shedding in anticipation of the next
outage.

Comment: This data was not considered as the respondent provided data for Category C3 Contingencies.
L

a. 2010, 2011, and 2012 Assessment Years
b. 1. 2010, 2011, and 2012 Assessments The 230 kV Line normally serves Substation.
The 230 kV Line is also connected to Substation in a flip-flop scheme, but the
connection is normally open. Substation has one 230/115 kV and two 230/70
kV Transformers. An outage of the 230 kV Line will trigger the SPS which opens
the 115 kV tie of the 230/115 kV Transformer. This action will result in
momentarily dropping roughly 140 MW of load connected to the two 230/70 kV
transformers. All customers will be restored within 1 minute when the flip-flop
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Question 3a Comment
scheme connects the 230 kV Line to Substation.
2. 2010 Assessment The 115 kV Line and the 115 kV Line serve Substation. An
outage of the 115 kV Line or the 115 kV Line results in an overload of the
remaining line. The resulting overload triggers the SPS which drops 40 MW of
70 KV and 115 kV load connected to Substation.
3. 2010 and 2011 Assessment The 230/60 kV Transformers Nos. 1 and 2/2a serve
the 60 kV area. An outage of the 230/60 kV Transformer No. 1 results in an
overload of the parallel 230/60 kV Transformer No. 2/2A triggering the Overload
Scheme which drops 40 MW load at 60 kV Substation.
4. 2010, 2011, and 2012 Assessments The 115 kV Line and the 115 kV Line, feed
the same 115 kV load area. An outage of the 115 kV Line results in an overload
of the 115 kV Line. This single contingency event triggers the Overload Scheme
which drops roughly 20 MW of load at 115 kV Substation.
c. 1. SPS: 140 MW
2. SPS: 40 MW
3. Overload Scheme: 40 MW
4. Overload Scheme: 20 MW
d. 1. SPS: One option to eliminate the load dropping scheme, is to convert the 230
kV bus to a ring bus operation. The 5-element new ring bus would cost about $M.
2. SPS: A transmission reinforcement, 70 kV to 115 kV Conversion, designed to
eliminate the need for load interruption was completed in at a cost of $M.
3. Overload Scheme: Replacement of the 230/60 kV Transformer No. 2/2A is
scheduled to be completed by summer at a cost of about $M.
4. Overload Scheme: In order to eliminate the load dropping scheme, the 115 kV
Line would need to be re-conductored at a cost of about $M.

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Question 3a Comment
e. 1. SPS: None - load is automatically restored within 1 minute.
2. SPS: Transmission reinforcement already completed. The 70 kV to 115 kV
Conversion was released to operations on
3. Overload Scheme: Summer 2013
4. Overload Scheme: None
f. 1. SPS:
2. SPS:
3. Overload Scheme:
4. Overload Scheme:
g. 1. SPS:
2. SPS: SPS no longer required and is not included as mitigation in the assessment
3. Overload Scheme: Overload scheme is no longer required and is not included as
mitigation in the assessment
4. Overload Scheme:

Comment: The 1st instance was not considered since the load dropped was automatically restored.
M

a. 2010. No instances are found in 2011 or 2012 Assessments.
b. In a winter peak situation, low voltages show up in the 115 kV area following a
loss of 115 kV. Affected buses are as follows: 115 kV, 115 kV, 115 kV, In this case
approximately 39 MW of winter peak load at 115 kV will be shed by UVLS in
addition to any load at 115 kV.
c. See (b).
d. The project is a 230 kV line and will eliminate the need for this UVLS for single
contingencies. The project cost is approximately $M and is expected to be

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Question 3a Comment
completed in September of 20.
e. See (d).
f. The area is mentioned in assessments dating back to 2006.
g. 2010

N

a. 2011 No planned interruption of Firm Demand.
2010 Interruption of Firm Demand.
2009 Interruption of Firm Demand.
Note: In some instances following a single contingency, the term shed load is used
in our Planning Assessments to address BES performance requirements following
a single contingency. Typically this is done to address possible violations at the
Point of Interconnection serving a neighboring LSE absent any guidance from said
LSE to mitigate the possible violation. This means that load shed would be
required within the LSE’s control area where N has no planning or operation
control. The LSE has their own plan of action and has not shared this information
with N.
b. 1) 2011/none
2) 2010/ ~40MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS/
PlanningModelYear: 2012S/ LSESheddingLoad:
3) 2010/ ~40MW/ 138kV/ OPEN LINE FROM BUS TO BUS / PlanningModelYear:
2012S/ LSESheddingLoad:
4) 2010/ ~3MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2012S/ LSESheddingLoad:
5) 2010/ ~20MW/ 138kV/ Description: OPEN LINE FROM BUS TO /
PlanningModelYear: 2016S/ LSESheddingLoad:
6) 2010/ ~15MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS
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Question 3a Comment
PlanningModelYear: 2016S/ LSESheddingLoad:
7) 2010/ ~63MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2016S/ LSESheddingLoad:
8) 2010/ ~40MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2016S/ LSESheddingLoad:
9) 2010/ ~40MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2016S/ LSESheddingLoad:
10) 2010/ ~3MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2016S/ LSESheddingLoad:
11) 2010/ ~62MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2016S/ LSESheddingLoad:
12) 2010/ ~40MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS CKT 1/ PlanningModelYear: 2016S/ LSESheddingLoad:
13) 2010/ ~61MW/ 138kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS / PlanningModelYear: 2016S/ LSESheddingLoad:
14) 2010/ ~4MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS / PlanningModelYear: 2016S/ LSESheddingLoad:
15) 2009/ ~7MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009S/ LSESheddingLoad:
16) 2009/ ~7MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009S/ LSESheddingLoad:
17) 2009/ ~6MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009W/ LSESheddingLoad:
18) 2009/ ~6MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009W/ LSESheddingLoad:
19) 2009/ ~4MW/ 69kV/ Description: OPEN LINE FROM BUS TO BUS /
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Question 3a Comment
PlanningModelYear: 2009W/ LSESheddingLoad:
20) 2009/ ~4MW/ 69kV/ Description: OPEN LINE FROM BUS TO /
PlanningModelYear: 2009W/ LSESheddingLoad:
21) 2009/ ~2MW/ 69kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009W/ LSESheddingLoad:
22) 2009/ ~2MW/ 69kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009W/ LSESheddingLoad:
23) 2009/ ~11MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2010S/ LSESheddingLoad:
24) 2009/ ~11MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2010S/ LSESheddingLoad:
25) 2009/ ~6MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS / PlanningModelYear: 2009S/ LSESheddingLoad:
26) 2009/ ~6MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009S/ LSESheddingLoad:
27) 2009/ ~20MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS /
PlanningModelYear: 2009S/ LSESheddingLoad:
28) 2009/ ~6MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS CKT 1/ PlanningModelYear: 2009W/ LSESheddingLoad:
29) 2009/ ~2MW/ 115kV/ Description: OPEN LINE FROM BUS TO BUS OPEN LINE
FROM BUS TO BUS OPEN LINE FROM BUS TO BUS / PlanningModelYear: 2009W/
LSESheddingLoad:
c. See data in question 3.b.
d. From data in question 3.b.
Item 2 & 8: Load shed is within the specified LSE or switching internal within their

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Organization

Question 3a Comment
transmission system. Their specific mitigation plan of action has not been shared
with N.
Items 3-7, 9, 10, 12, 13: LSE will move their entire load, thus load shedding will
not be applicable after this date as noted in the model.
Items 11: Load shed is within the specified LSE or switching internal within their
transmission system. Their specific mitigation plan of action has not been shared
with N. It should also be noted that this LSE has added and continues to added
generation which could alleviate, if not eliminate any load shed internal to their
system
Item 14: $M, In-Service Date (ISD) Items 15-16, 23-24: , $M, ISD,
Items 17,18,25,26,28: $M, ISD
Items 19-22, 27,29: $M, ISD
e. See response to question 3.d.
f. 2009
g. 2010. It should be noted that typically within the control area, the planned
interruption of Firm Demand has been used in the interim only as a measure of
last resort until transmission system reinforcements (upgrades) are budgeted,
permitted and built. Once the transmission upgrades are built, the interruption
of Firm Demand is not an issue under the consideration of normal load growth.

Comment: Data from the 4 69 kV lines cited above (items 19 – 22) not counted as these are not BES Facilities.
O

a. 2011 and 2012 Planning Assessments
b. 1. UVLS System: Loss of the 230/115-kV transformer (Cat B3); 9 MW,115-kV & 11
MW,69-kV.
2. UVLS System: Loss of the 230/115-kV transformer (Cat B3); 14 MW,115-kV.

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Question 3a Comment
c. 1. UVLS System: 20 MW.
2. UVLS System: 14 MW.
d. 1. UVLS System:$ Million.
2. UVLS System:$ Million.
e. 1. UVLS System: 20
2. UVLS System: 20.
f. 2011
g. 2012

P

a. 2011, 2010, 2009
b. The are fed by two 138 kV lines. On loss of one of those lines, the voltage stability
is close to collapse and the remaining line may overload at peak loads. As a
result, an Undervoltage Load Shedding Scheme (UVLS) sheds load to protect the
voltage stability, which, consequently, also protects the thermal loading on the
lines. Starting in a series capacitor will be installed just south of which will
eliminate most of the voltage stability issues and a Special Protection System will
be installed to supplement the UVLS scheme to shed load to protect the thermal
loading of the two lines north.
c. Between 20MW in the near-term horizon to about 55MW in the long-term
horizon.
d. We have not done an official estimate, but conceptual estimates are in the $
Million plus range; which is not a wise investment considering that the load that is
planned to be shed currently is also subject to consequential load loss for loss of
the single radial line from. Hence, the investment would have negligible impact
on the customer experience.

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Question 3a Comment
e. No investments are planned, see response to 3.d.
f. The first year identified in the most recent Planning Assessment is 2013.
g. Please see response to question 3.f.

Q

a. 2012
b. Instance 1: A 161kV line outage in: We plan to drop up to 28 MW of Firm
Demand to correct a 110% overload on a 138 kV line, 13MW at the 138kV level
and 15MW at the 46kV level
c. Just one instance in, so the answer is 28 MW
d. The instance can be eliminated with a new 138 kV line, estimated cost is $M.
e. The solution is in the planning phase with an in-service date of.
f. The 161 kV line outage concern was identified in the spring
g. The most recent instance of planned interruption of Firm Demand following a
single contingency was identified in 2012.

R

a. (through e.) 2011 Assessment Contingency kV (Cont) MW ISD Cost ($M)
500/115kV Auto 115kV 3.48
Summer 2012 $ Line 138kV 75.20
Summer 2013 $ Line 138kV 3.70
Summer 2013 $ Line 115kV 1.24
Summer 2013 $ Line 138kV 7.71
Summer 2013 $ Line 115kV 15.68
Summer 2014 $ Line 115kV 2.09
Summer 2014 $ Line 230kV 11.33
Summer 2015 $ Line 115kV 5.91
Summer 2015 $ Line 115kV 10.86
Summer 2015 $ Line 115kV 19.81

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Question 3a Comment
Summer 2015 $ Line 500kV 3.36
Summer 2018 $ Line 500kV 17.52 TBD
2010 Assessment Contingency kV (Cont) MW ISD Cost ($M) Line 115kV 4.99
Summer 2014 $ Line 115kV 0.33
Summer 2013 $ Line 115kV 5.00
Summer 2013 $ 500/115kV Auto 115kV 8.62
Summer 2013 $ Line 115kV 7.14
Summer 2012 $ 230/115kV Auto 115kV 2.69
Summer 2012 $ 230/115kV Auto 115kV 12.50
Winter 2011 $ Line 500kV 28.31
Summer 2013 $
f. 2010 - Loss of 230/115 kV auto
g. 2011 - Loss of 230 kV line
2010 - Loss 115 kV line
2011 - Loss of 500 kV line

S

a. The Substation load loss is an existing situation that is planned to be mitigated in.
The need for planned or controlled interruption of supply has also been
identified for two future. This need for load interruption arises starting in for the
90 MW and for the 128 MW.
b. Planning Assessments identified the possibility of non-consequential load loss at
120 kV Substation for an N-1 contingency of the single 230 kV transmission
source. This load is a single industrial customer in a remote location that cannot
be supplied by the underlying 55 kV system after a 230 kV outage. The described
N-1 contingency load loss is planned to be mitigated in by projects associated
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Organization

Question 3a Comment
with the addition of two new renewable generators in the area.
Expansion Planning Assessments include specific planned or controlled
interruption of supply for single contingencies within the Bulk Electric System for
two new remote additions. The loads are extremely large single loads (90 and
128 MW) located long distances from strong electrical infrastructure. Unlike
many high demand electrical loads, these loads cannot be moved closer to the
EHV BES. The locations of these loads are linked directly to the. These loads
belong to industrial customers with sophisticated knowledge of electrical service
who have requested these planned or controlled interruption of supply service
plans. A major concern to these customers is the length of time that would be
required to permit and construct any alternate plan of service that would
eliminate the planned interruption of their loads for an N-1 contingency.
These three load dropping plans of service each only interrupt the specific single
industrial customer mentioned. No other customers require load tripping for
these service plans.
1. 8 MW, 120 kV for an N-1 contingency of the 230 kV
2. 90 MW, 120 kV for loss of one of the two 120 kV sources to the location.
Service to is radial from the tap to the. Loss of the radial line also results in a loss
of this customer load.
3. 128 MW, 120 kV for loss of the two 120 kV sources to the location. Service to
the is radial from the tap to the. Loss of the radial line also results in a loss of this
customer load.
c. 1. Substation 8 MW
2. 128 MW
3. 90 MW
d. $ million for

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Question 3a Comment
2. $ million and a 3-5 year delay for
3. $ million and a 3-5 year delay for
For each of the large load additions, the customer was provided options which
would not have required planned load interruption for a single contingency.
These customers specifically rejected those options, primarily because of delayed
timing required to permit new transmission lines and the resulting project delay.
The lost productivity from three to five year delays was unacceptable for these
major operations. These three customers are the only loads subject to this type of
non-radial, N-1 curtailment.
e. As described above there are plans to mitigate the Substation load loss for N-1
contingencies by. Unless requested by or, or driven by additional load growth in
the region, there are no plans to eliminate these two cases of planned interruption
of Firm Demand.
f. 1990 only
g. 2012

Comment: Only the 1st instance shown in the table is Firm Demand for an N-1 Contingency. The other two instances
are interruptible load and were not considered.
T

a. 2012
b. 115 kV Under Voltage Load Shedding and 115 kV Under Voltage Load Shedding for the 115
kV contingency during winter peak conditions. (MW details found below in part (c))

115 kV Under Voltage Load Shedding and 115 kV Under Voltage Load Shedding for
115 kV contingency during winter peak conditions. (MW details found below in
part (c))
c. 2012 Assessment (models with interruption of firm demand for TPL-002)

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Question 3a Comment
2012 Winter Peak

2017 Winter Peak

115 kV

0 MW

0 MW

115 kV

3.6 MW

4.1 MW

115 kV

5.5 MW

6.4 MW

115 kV

2.3 MW

2.7 MW

d. 115 kV & 115 kV: $ Million

115 kV & 115 kV: $ Million
e. 115 kV & 115 kV:

115 kV & 115 kV:
f.

2009
g. 2012 – The primary cause of under voltage at the substations is loss of the 115 kV line at
times of low generation output from the. For this condition, the remaining 115 kV source
from is not strong enough to support the area loads. At this time, under voltage load
shedding is used to mitigate this concern. The situation outlined above does not affect
bulk transmission facilities, but is a local load-serving problem caused by limited
transmission facilities serving the area. Based on our knowledge, the Under Voltage Load
Shedding at has never operated due to a category B contingency since it was installed.

Consideration of Comments: Proposed Request for Data or Information Order No. 762

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I - response to 3b.
2010 Summer Assessment Examples
From

NAME

BASKV

AREA

To

NAME

Overload

Name of
Contingency 1
(N-1)

Mitigation
Plan

115

109.84%

Curtail 10 MW.

115

125.65%

115
115

109.16%
129.50%

Curtail 12 MW
of load
Curtail 5 Mw
Curtail 10 Mw.

Consideration of Comments: Proposed Request for Data or Information Order No. 762

44

Permanent
Solution to the
problem

2011 Assessment Examples
Example 1:
The 115 kV line from was planned to be under construction during the summer of 2012. During this season, several 115
kV outages caused low voltages which require load curtailments as shown below.
115 kV line
Contingency
115 kV
line

115 kV line

138 kV line
138/115 kV
transformer

Bus

VCont
0.75
0.74
0.82
0.80
0.46
0.45
0.53
1.05
1.06
1.05
1.06

Vmax
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05

Consideration of Comments: Proposed Request for Data or Information Order No. 762

Vmin
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90

Response Plan
Shed load (8.9 MW),
(22.9 MW and 18.2
MW)
Shed load (8.9 MW),
(22.9 MW)
Reduce cap bank to
no steps 0 MVAR

45

Example 2:
The 115 kV line from was planned to be under construction during the summer of 2012. During this season, several 115
kV outages caused low voltages which require load curtailments as shown below.
115 kV line
Contingency
115 kV
line

115 kV line

Bus

VCont
0.84
0.84
0.84
0.87
0.86
0.49
0.48
0.48
0.55

Vmax
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05

Consideration of Comments: Proposed Request for Data or Information Order No. 762

Vmin
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90

Response Plan
Shed load (22.9 MW)

Shed load (22.9 MW)

46

Example 3:
The 115 kV line from was planned to be under construction during the summer of 2012. During this season, several 115
kV outages caused low voltages which require load curtailments as shown below.
115 kV line
Contingency
115 kV
line

115 kV line

Bus

VCont
0.83
0.83
0.83
0.83
0.86
0.86
0.48
0.47
0.47
0.47
0.54

Vmax
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05
1.05

Consideration of Comments: Proposed Request for Data or Information Order No. 762

Vmin
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90
0.90

Response Plan
Shed load (22.9 MW)

Shed load (22.9 MW)

47

Example 4:
The 115 kV line from was planned to be under construction during the fall of 2012. During this season, several thermal
overloads were noticed and planned mitigations are shown below.
115 kV line
Contingency

Monitored Branch

Contingency

Monitored Branch

115 kV line

Rating (MVA) Flow
(MVA) % MVA
Response Plan
198

345/115 kV
transformer
115 kV line

233.9

118.1

transformer

336

352.8

105.0

Rating (MVA) Flow
(MVA) % MVA
Response Plan
Curtail 120 MW to
233 MW.
Shed load at (2.7
MW), (2.8 MW), (2.4
MW), (4.6
MW), and (4.6 MW);

END OF REPORT

Consideration of Comments: Proposed Request for Data or Information Order No. 762

48

Exhibit G
Summary of Proposed TPL Standards Development Authorization, Posting, and Balloting
History

EXHIBIT G
Summary of Post-Remand Development
Authorization, Posting, and Balloting History
A. Post-Remand Authorization

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
directives in Order No. 693 to address planned non-consequential load shed under limited
circumstances for single Contingencies.
B. The First Posting (July 2012): Informal Comment Period

The revised Footnote was posted for a first, informal comment period from
July 31, 2012 through August 29, 2012. 1 NERC received 51 sets of comments from
more than 117 different individuals, including 81 companies and representing 9 of the 10
industry segments. Commenters provided feedback on the draft Footnote. In response to
the comments received, the Drafting Team revised and clarified both the Footnote and
Attachment 1. The Drafting Team then requested that the Footnote and Proposed TPL
Standards be moved forward to the initial ballot and comment phase of the process.
C. The Second Posting (October 2012): Formal Comment Period and Initial Ballot

A revised draft of the Footnote was posted for a 45-day public comment period
(from October 5 through November 19, 2012) and subject to an initial ballot (from
November 9 through November 19, 2012). 2 The second draft reflected the revisions and
clarifications identified in Section B immediately above. NERC received 61 sets of

1

See Id. at pp. 789. Exhibit I page citations refer to page numbers of the pdf file filed with the
Petition and this Exhibit H.
2
See Id. pp. 1087.

comments from more than 149 different individuals, including 112 companies and
representing 9 of the 10 industry segments. Commenters provided feedback on the
Footnote and Attachment 1. The ballot was not approved, with 56.18% voting to approve
. 3 In response to the comments received, the Drafting Team further revised and clarified
both the Footnote and Attachment 1.
D. The Third Posting (December 2012): Formal Comment Period and Successive

Ballot
A third draft of the Footnote was posted for a 30-day public comment period
(from December 10, 2012 through January 11, 2013), and subject to a successive ballot
(from January 2 through January 11, 2013). 4 The third draft reflected further revisions
and clarifications as noted in Section C. NERC received 49 sets of comments from more
than 132 different individuals, including 48 companies and representing 9 of the 10
industry segments. The ballot was not approved, with 65.77% voting to approve, just
short of the two-thirds required to approve the ballot.
The Drafting Team made one change to the Footnote to address industry
comments following the third posting. Specifically, the main body of the Footnote and
Appendix 1 were revised to address a specific jurisdictional differences for non-US
entities – namely, that the 75 MW limit on planned, non-consequential load loss included
in the Footnote and Attachment 1 would not apply to Canadian or Mexican registered
entities. In addition, non-material clarifying, grammatical and typographical changes
were implemented. Because the revisions did not change the technical content or intent

3
4

See Id. pp. 1095.
See Id. at pp. 1333.

of the Proposed TPL Standards, and in order to support meeting the approaching
February 2013 deadline, the Standards Committee determined to move the project
forward to a recirculation ballot.
E. Final Balloting (January 2013): Recirculation Ballot

The Footnote proceeded to a recirculation ballot that concluded on January 31,
2013. 5 The recirculation ballot was approved, with 69.63% of the weighted segment vote
voting to approve the Footnote.
F. Board of Trustees Approval

The final draft of the stakeholder-approved Footnote, including Appendix 1, to be
included in the Proposed TPL Standards, was presented to NERC’s Board of Trustees for
approval on February 7, 2013. The Board of Trustees approved the Footnote
incorporated into the Proposed TPL Standards, and directed NERC staff to file the
Proposed TPL Standards with applicable regulatory authorities.

5

See Id. at pp. 1480.

Exhibit H
Consideration of Comments

Project 2010-11
TPL Table 1 Order
Related Files
Status:
Adopted by the NERC Board of Trustees on February 7, 2013 and pending
regulatory approval.

Purpose/Industry Need:
The SAR is to address FERC Order RM06-16-009 which required the ERO to clarify
TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption
of electric supply where a single contingency occurs on a transmission system by
June 30, 2010. The SAR provides a revision to TPL Table 1 footnote ‘b’ to provide
clarity to industry with regard to the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system. The
referenced table appears in TPL-001, TPL-002, TPL-003, and TPL-004 so while the
FERC Order was for TPL-002, the change is reflected in all 4 standards.

Draft

Action

Dates

Results

01/22/13
01/31/13
(closed)

Summary>>

01/02/13
01/11/13
(closed)

Summary>>

TPL-001-3 (formerly TPL-001-2a)
Clean | Redline to Last Posting
Implementation Plan
Clean | Redline to Last Posting

TPL-002-2b (formerly TPL-002-1c)
Clean | Redline to Last Posting

Recirculation
Ballot
Info>>

Ballot
Results>>

Vote>>

Implementation Plan
Clean | Redline to Last Posting
Draft 8
TPL-001-2a
Clean | Redline to Last Posting
Implementation Plan
Draft 7
TPL-002-1c

Successive
Ballot
Updated
Info>>
Info>>

Ballot
Results>>

Consideration
of Comments

Clean | Redline to Last Posting

Vote>>

Implementation Plan

Formal
Comment
Period

Supporting Materials:
Unofficial Comment Form (Word)

Info>>

12/10/12
01/11/13
(closed)

Comments
Received>>

Consideration
of Comments
(8)

Submit
Comments>>
Draft 7
TPL-001-2a
Clean | Redline to Last Posting
Implementation Plan
Draft 6
TPL-002-1c
Clean | Redline to Last Posting
Implementation Plan
Supporting Materials:
Unofficial Comment Form (Word)
Data Request Summary
FERC Order 762

Draft 1
TPL-001-3
Clean | Redline to Last Approved
TPL-002-1
Clean | Redline to Last Approved

Initial Ballot
Updated
Info>>
Info>>

11/09/12
11/19/12
(closed)

Updated
Summary>>
Full
Record>>

Vote>>
Formal
Comment
Period
Info>>

10/05/12
11/19/12
(closed)

Comments
Received>>

Consideration
of Comments
(7)

Comments
Received>>

Consideration
of Comments
(6)

Submit
Comments>>
Join Ballot
Pool>>

Comment
Period
Info>>
Submit
Comments>>

10/05/12
11/05/12
(closed)

07/31/12
08/29/12
(closed)

Supporting Materials:
Unofficial Comment Form (Word)
SAR
FERC Order 762

On April 19, 2012 FERC issued Order 762 remanding TPL-002-1b and FERC proposed to
remand TPL-001-2. NERC has been directed to revise footnote 'b' in accordance with the
directives of Order Nos. 762 and 693.

Implementation Plan
TPL-001-1
Clean | Redline to last posting
Redline to last approval
TPL-002-1b
Clean | Redline to last posting

Recirculation
Ballot

Redline to last approval
TPL-003-1a
Clean | Redline to last posting

Info>>

01/26/11
–
02/05/11
(closed)

Summary>>

12/27/10
-

Summary>>

Full
Record>>

Vote>>

Redline to last approval
TPL-004-1
Clean | Redline to last posting
Redline to last approval
Initial Ballot

Consideration
of Comments

Implementation Plan

Info>>

TPL-001-1

Vote>>

Clean | Redline to last posting

Ballot Pool

Redline to last approval

Info>>

01/05/11
(closed)

Full
Record>>

(5)

11/19/10
12/22/10
(closed)

TPL-002-1b
Clean | Redline to last posting
Redline to last approval
TPL-003-1a
Clean | Redline to last posting
Redline to last approval

Comment
Period

TPL-004-1

Info>>

Clean | Redline to last posting

Submit
Comments>>

11/19/10
01/05/11
(closed)

Comments
Received>>

Consideration
of Comments
(4)

Comments
Received>>

Comment
Report (3)

Redline to last approval

Supporting Materials:
Comment Form (Word)

Implementation Plan
TPL-001-1
Clean | Redline to last posting
tTPLTPL-002-1b
Clean | Redline to last posting
TTPL-003-1a

Comment
Period

Submit
Comments>>
| Info>>

09/08/10
10/08/10
(closed)

Clean | Redline to last posting
TPL-004-1
Clean | Redline to last posting
Supporting Materials:
Comment Form (Word)
SAR
Implementation Plan
TPL-001-1
Clean | Redline to last approval
TPL-002-1b
Clean | Redline to last approval
TPL-003-1a
Clean | Redline to last approval
TPL-004-1
Clean | Redline to last approval
Supporting Materials:
Comment Form (Word)

Initial Ballot
Vote>> |
Info>>
Pre-ballot
Review
Join>> |
Info>>
Comment
Period
Submit
Comments>>
| Info>>

05/17/10
05/27/10
(closed)

Summary>>
Full
Record>>

Comment
Report (2)

04/15/10
05/17/10
(closed)

04/15/10
05/26/10
(closed)

Comments
Received>>

Comment
Report (1)

Consideration of Comments on Project 2010-11: TPL Table 1 Order and
Comments Submitted with Initial Ballots
The Standards Committee thanks all commenters who submitted comments on the
proposed SAR for the TPL Table 1 Order. The SAR proposed changes to TPL Table 1 in
response to FERC’s Order RM06-16-009 which requires the ERO to clarify TPL-002-0, Table
1 - footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single contingency occurs on a transmission system by June 30, 2010. Table 1 is used in
TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be reflected
in all four of these TPL standards.
The SAR, implementation plan, and the clean and redline versions to the four TPL standards
were posted for a 40-day public comment period from April 15, 2010 through May 27, 2010.
Stakeholders were asked to provide feedback on the standards through a special electronic
comment form. There were 22 sets of comments, including comments from more than 80
different people from approximately 40 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.
The initial ballot for the proposed changes to the four TPL standards was conducted from
May 17-27, 2010. The comments submitted with initial ballots and the drafting team’s
responses to those comments are also contained in this report.
All comments submitted during the comment period and the initial ballot results are posted
on the following page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Based on stakeholder comments, the drafting team has made some additional changes to
Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes include
the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the
terminology used in the associated column heading of Table 1 – ‘Loss of Demand or
Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology
changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

The following bullet was added to Footnote ‘b’ to provide the flexibility requested by
stakeholders with respect to interrupting Demand, but with appropriate constraints to
protect reliability. The >90% demand level was selected to ensure that the number of
hours with exposure to demand loss was not unlimited. A 90% demand level is a
reasonably stressed case for most systems and the number of hours when peak demands
are >90% is a small percentage of the time for most systems. A large percentage of the
transmission lines that directly serve distribution customers are 161 kV or lower voltages.
Ten percent (10%) of the loading on a high capacity 161 kV transmission line is
approximately 50 MW.
•

Planned or controlled interruption of Demand required to address postContingency performance issues that occur at Demand levels greater than 90%
of forecasted Peak Demand provided that the Demand being interrupted does not
exceed 50 MW

The following bullet was added to Footnote ‘b’ to clarify that it is acceptable to use
Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

The above changes will be noted to stakeholders before the initiation of the recirculation
ballot.
The revised Footnote ‘b’ is:

b) No interruption of projected customer Demand is allowed except:
o

Interruption of Demand that is directly served by the elements that are removed from
service as a result of the Contingency

o

Planned or controlled interruption of Demand supplied by Transmission Facilities
made temporarily radial as a result of the Contingency and where that Demand must
be interrupted to meet performance requirements only on those now radial
Transmission Facilities

o

Planned or controlled interruption of Demand required to address post-Contingency
performance issues that occur at Demand levels greater than 90% of forecasted Peak
Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Comments and Responses from Formal Comment Period:
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system by June 30, 2010. Do you agree with the proposed changes and if not, please provide specific
reasons for your disagreement. .............................................................................................................................. 9

2.

Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any regulatory function,
rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the conflict. ................................... 21

Comments and Responses from Initial Ballot:
3.

Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010 ..................................... 26

June 10, 2010

3

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Commenter

Organization

Industry Segment
1

1.

Group

Guy Zito
Additional Member

2

3

4

5

6

8

9

10

Northeast Power Coordinating Council

X

Additional Organization

Region

Segment Selection

1. Alan Adamson

New York State Reliability Council

NPCC

10

2. Greg Campoli

New York Independent System Operator

NPCC

2

3. Roger Champagne

Hydro-Quebec TransEnergie

NPCC

2

4. Kurtis Chong

Independent Electricity System Operator

NPCC

2

5. Sylvain Clermont

Hydro-Quebec TransEnergie

6. Chris de Graffenried

Consolidated Edison Co. of New York, Inc.

NPCC

1

7. Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

8. Ben Eng

New York Power Authority

NPCC

4

9. Brian Evans-Mongeon

Utility Services

NPCC

8

10. Mike Garton

Dominion Resources Services, Inc.

NPCC

5

11. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

12. Kathleen Goodman

ISO - New England

NPCC

2

13. David Kiguel

Hydro One Networks Inc.

NPCC

1

14. Peter Yost

Consolidated Edison Co. of New York, Inc.

NPCC

3

June 10, 2010

7

1

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6

15. Randy MacDonald

New Brunswick System Operator

NPCC

2

16. Bruce Metruck

New York Power Authority

NPCC

6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18. Robert Pellegrini

The United Illuminating Company

NPCC

1

19. Saurabh Saksena

National Grid

NPCC

1

20. Michael Schiavone

National Grid

NPCC

1

2.

South Carolina Electric & Gas

Group

Philip R. Kleckley
Additional Member

X

Additional Organization

X
Region

Southern Company Services - Trans.

SERC

1

Tennessee Valley Authority

SERC

1

3. Charles Long

Entergy

SERC

1

4. James Manning

North Carolina Electric Membership Corporation

SERC

3

5. Pat Huntley

SERC Reliability Corporation

SERC

10

John Bee

Exelon Transmission Strategy & Compliance

Additional Member

X

Additional Organization

X
Region

Segment Selection

:(ComEd)

RFC

1

2. Weaver, David W

(PECO)

RFC

1

3. McHugh, Kathleen P

(PECO)

RFC

1

4. Kay, Thomas W

(ComEd)

RFC

1

5. Szymczak, Ronald

(ComEd)

RFC

1

6. Chu, Ron F

(PECO)

RFC

1

7. Donnelly, Michael J

(PECO)

RFC

1

8. Kliros, Chris B

(ComEd)

RFC

1

9. Mills, Paul M

(ComEd)

RFC

1

10. Webb, Becky

(ComEd)

RFC

1

Group

Denise Koehn

June 10, 2010

BPA, Transmission Reliability Program

X

X

10

X

1. Mortenson, Eric

4.

9

Segment Selection

2. David Marler

Group

8

X

1. Bob Jones

3.

7

X

X

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

Additional Member

2

Additional Organization

3

4

5

6

Region

BPA, Transmission Planning

WECC

1

2. Berhanu Tesema

BPA, Transmission Planning

WECC

1

3. Larry Furumasu

BPA, Transmission Planning

WECC

1

4. Kyle Kohne

BPA, Transmission Planning

WECC

1

5. Don Watkins

BPA, Transmission System Operations

WECC

1

6. Rebecca Berdahl

BPA, Power, Long Term Sales and Purchases

WECC

3

Group

Carol Gerou
Additional Member

Additional Organization

Region

Segment Selection

MRO

1

2. Tom Webb

Wisconsin Public Service

MRO

3, 4, 5, 6

3. Terry Bilke

Midwest ISO Inc.

MRO

2

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

7. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

8. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

Richard Kafka

Pepco Holdings, Inc.

Additional Member

X

X

Additional Organization

X

X

Region

Segment Selection

1. Jim Summers

Delmarva Power and Light Co.

RFC

1

2. John Radman

Potomac Electric Power Company

RFC

1

7.

Group

Ben Li
Additional Member

June 10, 2010

10

X

American Transmission Company

Group

9

Midwest Reliability Organization

1. Chuck Lawrence

6.

8

Segment Selection

1. Chuck Matthews

5.

7

IESO

X
Additional Organization

Region

Segment Selection

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

1. Bill Phillips

MISO

MRO

2. James Castle

NYISO

NPCC

3. Charles Yeung

SPP

SPP

4. Lourdes Estrada-Salinero

CAISO

WECC

5. Patrick Brown

PJM

RFC

6. Steve Myers

ERCOT

ERCOT

8.

Group

Frank Gaffney

Florida Municipal Power Agency

Additional Member

2

3

X

Additional Organization

4

5

6

X

X

X

Region

Utilities Commission of New Smyrna Beach

FRCC

4

2. Greg Woessner

Kissimmee Utility Authority

FRCC

1

3. Jim Howard

Lakeland Electric

FRCC

1

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services

FRCC

1

6. Cairo Vanegas

Fort Pierce Utility Authority

FRCC

4

Individual

Stephen Mizelle

Southern Company Transmission

X

Robert Casey

Georgia Transmission Corporation (Bulk
System Planning)

X

Individual
11.

Individual

Thad Ness

American Electric Power

X

X

X

X

12.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

13.

Individual

Martin Bauer

US Bureau of Reclamation

14.

Individual

Kirit Shah

Ameren

X

X

X

15.

Individual

Robert W. Roddy

Dairyland Power Cooperative

X

X

X

10.

June 10, 2010

8

9

10

Segment Selection

1. Timothy Beyrle

9.

7

X
X

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6
X

16.

Individual

Marty Berland

Progress Energy

X

X

X

17.

Individual

Michael R. Lombardi

Northeast Utilities

X

X

X

18.

Individual

Charles Lawrence

American Transmission Company

X

19.

Individual

Greg Rowland

Duke Energy

X

X

X

X

X

X

X

Bill Middaugh

Tri-State Generation and Transmission
Association, Inc.

X

Individual
21.

Individual

Roger Champagne

Hydro-Québec TransEnergie (HQT)

X

22.

Individual

Dan Rochester

Independent Electricity System Operator

20.

June 10, 2010

7

8

9

10

X

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which
required the ERO to clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system by June 30, 2010. Do you agree with the proposed
changes and if not, please provide specific reasons for your disagreement.
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made
changes to the footnote to balance the various industry concerns while assuring BES reliability.
The 3rd bullet has been added to provide the flexibility requested by industry with appropriate constraints. This is limited by two conditions: >90%
demand level and 50 MW. The >90% demand level was selected to ensure that the number of hours with exposure to demand loss was not
unlimited. A 90% demand level is a reasonably stressed case for most systems and the number of hours when peak demands are >90% is a
small percentage of the time for most systems. A large percentage of the transmission lines that directly serve distribution customers are 161 kV
or lower voltages. Ten percent (10%) of the demand on a high capacity 161 kV transmission line is approximately 50 MW.
th

A 4 bullet has also been added to clarify that it is acceptable to use Interruptible demand and Demand-Side Management.
To match the terminology in the revised footnote with the terminology in the associated column heading (Loss of Demand or Curtailed Firm
Transfers) the term, ’Load’ was replaced with ‘Demand’ and the term ‘Firm Transmission Service’ was replaced with ‘firm transfers.’
Footnote ‘b’ now reads:

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Duke Energy

No

Duke Energy voted "Negative" on the initial and current ballots of TPL-001-1, primarily because Duke believes
that the requirement prohibiting loss of non-consequential load for P1, P2.1 and P3 events is an overreach by
the standard into local load quality of service issues. We also sought rehearing on the Commission’s March
18 Order Setting Deadline for Compliance (Docket No. RM06-16), with respect to this and other issues. We
believe that FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of a
single contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power
system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many instances, it may be in the
best interest of all involved parties from an overall cost/benefit point of view to allow loss of non-consequential
load.
Duke offers the following ideas on alternatives for the SDT to consider that will allow for appropriate discretion
and facilitate proper planning while allowing non-consequential load loss (NCLL).The standard should allow
for dropping of limited amounts of non-consequential load in situations where it would be reasonable for a
bounded time period and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations where the near term
impact of load projections or implementation of nearby transmission/generation projects will alleviate the
necessity of an upgrade to meet N-1 conditions. Also, reliability of service to end-use customer is impacted by
the entire system from source to load. Where allowance for NCLL would not greatly impact individual enduse customers’ level of reliability the transmission planner should consider its use. Normally transmission
system outages are a minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to avoid projects without greatly impacting a customer’s outage frequency

June 10, 2010

10

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
and duration should be acceptable. Use of reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be
considered by the SDT for determination of acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
The SDT discussed the use of reliability metrics for providing flexibility to planners but has not included their use as this would make the implementation too
complex.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Midwest Reliability Organization

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Dairyland Power Cooperative

No

DPC concurs with the MRO comments: For Footnote b, add a third exception to the list, "or (3) end-use load
that is either accepted or volunteered by the customer". It is a widely-held understanding that the tripping of
non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered
by the customer in lieu of significant transmission system modifications.

American Transmission
Company

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant

June 10, 2010

11

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
transmission system modifications.

Response: The SDT has added the fourth bullet to address your concern.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Georgia Transmission
Corporation (Bulk System
Planning)

June 10, 2010

No

Georgia Transmission Corporation (GTC) believes that the requirement prohibiting loss of non-consequential
load for P1, P2.1 and P3 events is an overreach by the standard into local load quality of service issues. We
believe that FERC’s directive in (Docket No. RM06-16) to prohibit the loss of non-consequential load in the
event of a single contingency appears to extend beyond measures needed for “reliable operation” of the bulkpower system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the cost of major projects. In
many instances, it may be in the best interest of all involved parties from an overall cost/benefit point of view

12

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
to allow loss of non-consequential load.We also note that on April 19 NERC filed a request for rehearing with
FERC asking that the Commission revise the directive in Paragraph 8 of the March 18 TPL-002 Order to allow
NERC the necessary time to incorporate changes to the TPL-002 Reliability Standard through the Reliability
Standards Development Process that are necessary to achieve bulk power system reliability. NERC also
requested that the Commission grant NERC’s Motion for Stay to stay the Order so that a public technical
conference with opportunity for comment can be held in order to provide parties an opportunity to meet and
discuss the technical considerations of developing a modification to the TPL-002 standard that prohibits the
loss of non-consequential firm load in the event of an N-1 contingency. NERC’s April 19 filing pointed out that
if the Commission’s directive to disallow the loss of non-consequential firm load for an N-1 contingency is
implemented, a question is presented regarding whether the Reliability Standard still serves the purpose of
ensuring the Reliable Operation of the bulk power system by preventing instability, uncontrolled separation,
and cascading failures. That is, the Commission’s directive sets forth an expectation that NERC is to
implement standards that address all loss of load at costs that may not be commensurate with bulk power
system reliability, as statutorily defined, which is fundamentally different from what the Reliability Standards
were intended to do.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Progress Energy

June 10, 2010

No

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect to conditional
allowance of curtailing Firm Transmission Service, which is addressed in the second paragraph of the
proposed new footnote (b). PE remains concerned, however, that the first paragraph of the proposed new

13

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
footnote (b) does not allow for curtailment of non-radial non-consequential load. The ability to curtail nonconsequential load in the planning horizon can be a useful tool to mitigate local area issues, and has not been
detrimental to the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly at a localized selfcontained level of the system, i.e. the distribution system(s) served by the Transmission Owner/Operator.
Prohibiting the curtailment of local load thus constitutes regulating distribution feeder reliability rather than
BES reliability. Events that could be mitigated through the curtailment of local, non-radial non-consequential
load are infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the proposed footnote (b)
be considered:”No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served
by the elements that are removed from service as a result of the Contingency, and/or (2) Planned or
controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now
radial Transmission Facilities, and/or (3) Planned or controlled interruption of any additional Load required to
mitigate the post-contingency results, provided that the non-consequential load being shed for the event is
localized, and provided that the total load shed for the event does not exceed 2% of the Planned system peak
demand or 200 MW, whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
The SDT did adopt a limit but felt that 2% of system peak or 200 MW was not equitable for all entities.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.

June 10, 2010

14

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Hydro-Québec TransEnergie
(HQT)

Yes or No

Question 1 Comment

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Northeast Power Coordinating
Council

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Response: The SDT believes that it has been responsive to the FERC directive in that the standards development process has been employed. In the

June 10, 2010

15

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

development of the footnote, the SDT has balanced the need for discretion while addressing local area concerns with the need to assure the reliability of the BES.
‘Must’ is not appropriate in a footnote as it would impose a requirement in the footnote. The SDT has replaced ‘should’ with ‘would’ to correct the grammar.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Tri-State Generation and
Transmission Association, Inc.

No

Tri-State does believe that the new footnote is an improvement, but thinks there are still some changes
necessary. We believe that the word “only” should be removed from the phrase “...where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities” because that
discrimination was not required in FERC Order RM-06-16-009. There may be times when facilities near the
temporary radial facilities might also fall outside the limits set in reliability criteria but the situation is mitigated
if the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State recommends changing it to
"Curtailment of Firm Transmission Service is not allowed unless it is coupled with curtailment-offsetting
resources that are obligated to re-dispatch. Further, the curtailment activities cannot result in the shedding of
any Firm load or in violations of Facility Ratings, either internal or external to the planning region."

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. Instead of removing the word ‘only’, the 3 bullet has been added to provide the flexibility requested by
industry with appropriate constraints.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

16

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Southern Company Transmission

No

We propose that the section in double parentheses be deleted. The proposed wording by the drafting team
seems to imply that the curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language stated only that
curtailments were permitted to prepare for the next contingency, not to address loading related to the initial
contingency. The proposed wording could be interpreted to allow redispatch/firm curtailments to address any
single contingency constraint.
Southern Companies recommend that the original language relating to “preparing for the next contingency” be
incorporated into the drafting team’s proposal.((Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted element or by the
affected area, may occur in certain areas without impacting the overall reliability of the interconnected
transmission systems. To prepare for the next contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric power Transfers.)) No interruption of firm
Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities. To prepare
for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (nonrecallable reserved) electric power transfers No curtailment of Firm Transmission Service is allowed except
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch. where it can It must be
demonstrated that Facilities remain within applicable Facility Ratings and those adjustments do not result in
the shedding of any firm Load. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions should also be respected.

June 10, 2010

17

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the
Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in
the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity is obligated to redispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that
impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed. Therefore, the SDT does not believe that it is
nd
necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2 paragraph to provide additional
clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
South Carolina Electric & Gas

Yes

For better clarity delete the phrase “when coupled with” in the second paragraph of footnote ‘b.’

Response: The SDT did not delete the suggested phrase as it believes it is correct as stated but added commas to make the phrase read more clearly.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

June 10, 2010

18

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Independent Electricity System
Operator

Yes

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES and Firm Demand
and on the understanding that the NERC standards apply only to the BES as defined in the NERC Glossary
as follows:”As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally operated
at voltages of 100 kV or higher. Radial transmission facilities serving only load with one transmission source
are generally not included in this definition.” To be clear, our interpretation of the present definition of BES is
that it defers to each Regional Reliability Organization to define the elements of the power system that are
considered BES and, therefore in the NPCC Region, "BES as defined by NERC" = "BPS as defined by
NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
BPA, Transmission Reliability
Program

Yes

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with "Firm Transfers" to
be consistent with the fourth column of the existing Table 1 Transmission System Standards - Normal and
Emergency Conditions.

Response: The SDT agrees and has made the change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

June 10, 2010

19

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No
o

Question 1 Comment

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
American Electric Power

Yes

Exelon Transmission Strategy &
Compliance

Yes

Florida Municipal Power Agency

Yes

IESO

Yes

Northeast Utilities

Yes

Pepco Holdings, Inc.

Yes

US Bureau of Reclamation

Yes

Manitoba Hydro

Yes

MH agrees with the SDT proposal.

Ameren

Yes

We were ok with the previous language. Though we do not intend to drop non-consequential load for a single
contingency, we undersatnd that other ares may have been following such practice without degarding the
relaibility of BES. We believe that they can continue this practice if they develop non-firm contracts with these
customers.

Response: Thank you for your support.

June 10, 2010

20

Consideration of Comments on TPL Table 1 Order — Project 2010-11

2. Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the
conflict.
Summary Consideration: The SDT understands that there may be conflicts as pointed out by respondents; however, the SDT believes that
there should be constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustments the re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization

Yes or No

Ameren

No

American Electric Power

No

American Transmission
Company

No

BPA, Transmission Reliability

No

June 10, 2010

Question 2 Comment

21

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

Program
Dairyland Power Cooperative

No

Exelon Transmission Strategy &
Compliance

No

Independent Electricity System
Operator

No

Manitoba Hydro

No

Midwest Reliability Organization

No

Southern Company Transmission

No

US Bureau of Reclamation

No

South Carolina Electric & Gas

No

The comments expressed herein represent a consensus of the views of the above named members of the
SERC Engineering Committee Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.

Hydro-Québec TransEnergie
(HQT)

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

Northeast Power Coordinating
Council

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

Response: Thank you for your response.

June 10, 2010

22

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

IESO

Yes

It should be noted that conflicts may arise between individual state commissions, who may have rate recovery
authority, and utilities who attempt to abide explicitly with FERC’s position on non-consequential load loss. In
RM-06-16-009, the Commission again references Order 693 and specifically highlights comments by Duke
Power Company and Northern Indiana Public Service Company by saying the arguments made to date to
allow non-consequential load loss after a single contingency event is “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to invest in the bulk
electric system to the point that it can continue service to all firm load customers under some specific N-1
scenarios.” In the US, State commissions with rate recovery authority may take the position that considering
the economics of proposed investments intended to prevent non-consequential loss of small or remote load is
acceptable. This potential conflict between state and federal positions could place utilities in a compromising
position.Similar conflicts may also exist in Canada.

Progress Energy

Yes

There is the potential for conflict between Table 1 - Footnote (b) as currently proposed, which can be
considered to regulate local distribution reliability without improving BES reliability, and local service reliability
issues which are under the purview of state regulatory agencies. For example, the North Carolina Utilities
Commission (NCUC) commented regarding this concern in the ballot which ended March 1 in Project 200602. Specifically, NCUC commented that they were “...concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1 is an inappropriate overreach into service issues that
are more appropriately addressed by state regulatory commissions...” Progress Energy believes that NCUC’s
concerns are legitimate. BES reliability should address the avoidance and mitigation of cascading outages
and BES facility damage, rather than limited, controlled local area loss of load, in order to avoid this conflict
and overlap of regulation.

Response: The SDT understands the issue; however, the SDT believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES.
Northeast Utilities

Yes

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can be better defined as
the proposed revision is subject to interpretation by the different entities and regulatory agencies. Future
conflicts can be minimized by further clarifying the proposed revision.
Also, NU is concerned that this new modification does not specify the amount of permissible load shed nor
does it require the planning entity to minimize load shedding under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
The SDT has modified the footnote for clarity and added constraints in new bullet 3 to address your specific concern.

June 10, 2010

23

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Duke Energy

Yes

See response to question #1.

Georgia Transmission
Corporation (Bulk System
Planning)

Yes

See response to Question #1.

Response: See response to question #1.
Florida Municipal Power Agency

Yes

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all honesty, shedding load
for local area impacts has nothing to do with BES reliability and should not be under FERC jurisdiction under
Section 215 of the Federal Power Act, but rather State jurisdiction for quality of service issues. However,
there is also the matter of FERC jurisdiction over commercial matters and the opportunity to “game” the
original footnote by transmission providers by allowing firm load shedding to grant firm transmission service
for themselves, thereby avoiding or deferring transmission investment, while at the same time denying or
requiring others to build the same transmission avoided in order to obtain transmission service. We can see
how difficult it is from a drafting team’s perspective in achieving a balanced position between these different
matters. The drafting team should be applauded for finding a reasonable position.

Pepco Holdings, Inc.

Yes

This is not an issue for historic PJM members, but as PJM has expanded and as a result of the merger of
historic councils into RFC, I am aware that not all regions had standards equal to those of MAAC, and this

June 10, 2010

24

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment
has been an issue worked out between transmission planners (historic transmission owners) and their local
regulators. It is ultimately a cost issue for loss of local load that does not affect the overall reliability of the
interconnected BES.

Response: Thank you for your support.
Tri-State Generation and
Transmission Association, Inc.

Yes

We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of non-consequential load
in the event of a single contingency appears to extend beyond measures needed for “reliable operation” of the
bulk-power system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur
when utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their
planning protocols appears to extend the Commission’s reach beyond its review of measures that are needed
for “reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act.
Such directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal
Power Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality
of service issues applicable to local load.

Response: The SDT is not in a position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.

June 10, 2010

25

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

3. Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made changes to
the footnote to balance the various industry concerns while assuring BES reliability.
The 3rd bullet has been added to provide the flexibility requested by industry with appropriate constraints. This is limited by two conditions: >90%
demand level and 50 MW. The >90% demand level was selected to ensure that the number of hours with exposure to demand loss was not
unlimited. A 90% demand level is a reasonably stressed case for most systems and the number of hours when peak demands are >90% is a
small percentage of the time for most systems. A large percentage of the transmission lines that directly serve distribution customers are 161 kV
or lower voltages. Ten percent (10%) of the demand on a high capacity 161 kV transmission line is approximately 50 MW.
th

A 4 bullet has also been added to clarify that it is acceptable to use Interruptible demand and Demand-Side Management.
The second paragraph of the footnote has been clarified and references Firm Transfers now instead of Firm Transmission Service.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustments the re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Voter
Rodney
Phillips

Entity
Allegheny Power

June 10, 2010

Segment

Vote

Comment

1

Negative

Allegheny Power believes the loss of non-consequential load and/or curtailment of
transmission service for N-1 contingencies should be limited to only extreme circumstances.
Exception 2 of footnote b allows for the loss of non-consequential load for N-1

26

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
contingencies with no restriction. Allegheny Power recommends removing exception 2
footnote b.

Response: The SDT and the majority of the commenters disagree with this suggestion.
Gordon
Rawlings

BC Transmission
Corporation

1

Negative

Faramarz
Amjadi

BC Transmission
Corporation

2

Negative

Hubert C.
Young

South Carolina
Electric & Gas Co.

3

Negative

SCE&G has significant concern with the proposed revision to TPL Table 1, Footnote B. The
current Footnote B states “Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the
overall reliability of the interconnected transmission systems” is important to the TPL
standards to ensure that ERO standards do not dictate the level of service to customers.
Service to customers and load pockets is jurisdictional to State Commissions and ERO
standards should not compromise this jurisdiction. SCE&G believes that any proposed
revisions to Footnote B must retain the concept that planned or controlled interruption of
electric supply to customers, whether they are radial or network, is allowed as long as it
does not impact the overall reliability of the interconnected transmission systems. The
proposed revision eliminates this concept. There seems to be a general inconsistency and
maybe confusion between the terms “reliability” and “level of service”.

David Frank
Ronk

Consumers Energy

4

Negative

James B
Lewis

Consumers Energy

5

Negative

The current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the previous version of TPL-001-1. However, it still does
not allow Transmission Planners to use appropriate and necessary discretion regarding loss
of non-consequential load. Transmission Planners, customers, and local regulators should
control the decision making when BES reliability is not an issue. Often, the consequences of
these events are solely local in nature, requiring only minor additional loss of local load to

June 10, 2010

BCTC appreciates the good work of the SAR committee in drafting the changes to Footnote
b of Table 1. BCTC agrees with the drafting team that interruption of firm load, served by
either radial circuits or circuits that have became radial as a result of the contingency,
should be allowed for N-1 contingencies. However, it is our position that interruption of
firm load should not be limited only to such consequential loads. In our view, interruption
of electric supply to some local network customers in the affected area should be
permissible. This inclusion will allow transmission planners to plan BCTC’s regional
transmission network reliably and without impacting neighbouring transmission networks.

27

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
avoid the costly major projects. In many instances, it may be in the best interest of all
involved parties from an overall cost/benefit point of view to allow loss of nonconsequential load.

Hugh A.
Owen

Public Utility
District No. 1 of
Chelan County

6

Negative

The interruption of a small amount of load is, under most conditions, not a risk to the
reliability of the BES and is at times necessary to preserve reliability. The planned
interruption of some load may be a cost effective alternative to a costly transmission
project. That is a quality of service issue.

Michael
Gammon

Kansas City Power
& Light Co.

1

Negative

Charles
Locke

Kansas City Power
& Light Co.

3

Negative

Thomas
Saitta

Kansas City Power
& Light Co.

6

Negative

While the current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the recently balloted version of TPL-001-1, it still does
not allow Transmission Planners to use appropriate discretion regarding loss of nonconsequential load. Transmission Planners, customers, and local regulators should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load.

Linda Brown

San Diego Gas &
Electric

1

Affirmative

June 10, 2010

As to item (1), all load served directly by a transmission element which experiences a fault
will be interrupted when the faulted element is taken out of service. This is the natural
relationship between the load and the transmission element. Allowing this for BES elements
may encourage transmission owners to remove transmission instead of upgrading or
replacing it. Consider a load supplied by two transmission lines of different capacity. If the
larger line is lost due to a contingency (N-1) and the remaining smaller line overloads the
transmission owner is left with several options to address the problem: (1) move load
between buses, (2) upgrade the smaller line, (3) add another line, or (4) create a radial
load by removing the smaller line. Number (4) may be the least expensive and allowable
under TPL-002, footnote b. Item (2) may also encourage transmission owners to develop
plans which make load shedding part of category B. Consider a load served by three
transmission lines, a utility may decide to remove a line, instead of upgrading, in order to
set up a situation where an N-1 contingency would make the bus temporarily radial. In the
event of a single outage (N-1), the load bus will be temporarily radial and load can be shed
at the bus.

28

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

W. R.
Schoneck

Florida Power &
Light Co.

3

Affirmative

I believe the language is an improvement and clarifies the intent but I believe there still
should be additional language added to give an exemption in meeting this requirement if it
does not make economic sense(not economically feasible) and has no real impact on the
BES.

Richard J
Kafka

Potomac Electric
Power Co.

1

Affirmative

It is understood that this is a compliance filing issue. This is not an issue for historic PJM
members, but as PJM has expanded and as a result of the merger of historic councils into
RFC, I am aware that not all regions had standards equal to those of MAAC, and this has
been an issue worked out between transmission planners (historic transmission owners)
and their local regulators. It is ultimately a cost issue for loss of local load that does not
affect the overall reliability of the interconnected BES.

Alan Gale

City of Tallahassee

5

Affirmative

TAL thanks for SDT for the tireless effort to get to this point. TAL is voting affirmative with
the following comments. We accept that the loss of non-consequential load is not a desired
result for N-1 contingencies. It is also not the norm in system planning or operations. The
flexibility to operate the system consistent with “good utility practice” may warrant the
“odd-ball” case that would require this to occur. The dropping of non-consequential load
will NOT lead to BES instability, voltage collapse, or cascading outages, which is what FERC
and NERC are charged with preventing. It will lead to the shedding of load in a local area
only. Utilities do not drop customers lightly. If the meter isn’t turning, we are not getting
paid, so we want the meter spinning. Utility power, while vital to our normal day-to-day
lives and infrastructure, was never intended to be without interruption.

Brad Chase

Orlando Utilities
Commission

1

Affirmative

This change raises the bar on transmission system performance. This change applies a
blanket requirement upon entities that does not take into account the number of outages,
probability of outages or cost to the customer. There are certain to be situations where this
blanket requirement will result in increased cost to customers for no noticeable increase in
reliability. OUC does agree with the concept of greater clarification on this requirement,
however this clarification may raise the bar to far by trying to establish a blanket
requirement. Duke, Progress Energy and others will be submitting comments with
proposed language that attempt to address some of these issues and we encourage the
drafting team to consider those comments.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate

June 10, 2010

29

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

constraints.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Eric Egge

Black Hills Corp

June 10, 2010

1

Negative

Black Hills believes that the prohibition of loss of non-consequential load for events
resulting in the loss of a single element inappropriately reaches beyond the reliability of the
bulk power system to local load quality of service issues. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. NERC should be
allowed to hold a public technical conference, as described in NERC’s April 19, 2010,
request for rehearing before being required to develop and submit clarifications to footnote
b of Table 1.

30

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Negative

PG&E commends the SDT for developing the proposed footnote b. While it is a great
improvement over the complete prohibition on loss of non-consequential load for any single
contingency, the planned and controlled interruption of a small amount of load, under
certain conditions, is not a risk to reliability or an indication of an unreliable system, but
rather, serves to preserve the reliability of the bulk power system. Transmission Planners
and Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system, especially where the impact is local in nature, to avoid
instability, cascading or uncontrolled separation. Such planned interruption of load may be
a reasonable alternative to the environmental impacts or prohibitive costs associated with a
major new transmission project. Given the potential impacts of the proposed modification,
further vetting of the issues is needed. PG&E believes that NERC should be allowed to hold
a public technical conference, as described in NERC’s April 19, 2010, request for rehearing
before being required to develop and submit clarifications to footnote b of Table 1.

Thomas J.
Bradish

RRI Energy

5

Negative

Trent
Carlson

RRI Energy

6

Negative

RRI supports the WECC position on this issue; namely, that the prohibition of loss of nonconsequential load for events resulting in the loss of a single element inappropriately
reaches beyond the reliability of the bulk power system to local load quality of service
issues. The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project. NERC should be allowed to hold a public technical conference, as
described in NERC’s April 19, 2010, request for rehearing before being required to develop
and submit clarifications to footnote b of Table 1.

June 10, 2010

31

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

John Tolo

Tucson Electric
Power Co.

1

Negative

The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project.

James
Tucker

Deseret Power

1

Negative

The prohibition of loss of non-consequential load for events resulting the loss of a single
element inappropriately reaches beyond the reliability of the bulk power system to local
load quality of service issues. The planned and controlled interruption of a small amount of
load, under certain conditions, is not a risk to reliability or an indication of an unreliable
system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

Louise
McCarren

Western Electricity
Coordinating
Council

10

Negative

The proposed revisions to footnote b of Table 1 are an improvement to the recently
balloted prohibition on loss of non-consequential load for single contingencies. The
recognition of the new term "temporarily radial" is a step in the right direction. However,
the planned and controlled interruption of a small amount of load, under certain conditions,
is not a risk to reliability or an indication of an unreliable system, but rather, serves to
preserve the reliability of the bulk power system. Transmission Planners and Planning
Coordinators should be given the discretion to determine whether or not the planned and
controlled interruption of load is an appropriate system response to certain contingencies,
taking into consideration all factors, including customer and local regulator input, for their

June 10, 2010

32

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
individual system. Often times when planned load interruption is identified as a response to
a single event, the impact to the system is local in nature. The planned interruption of load
may be the alternative to prohibitive costs associated with a major new transmission
project. NERC should be allowed to hold a public technical conference, as described in
NERC’s April 19, 2010, request for rehearing before being required to develop and submit
clarifications to footnote b of Table 1.

William
Mitchell
Chamberlain

California Energy
Commission

9

Negative

While the proposed revisions to footnote b are an improvement to the prohibition on loss of
non-consequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, the prohibition of loss of non-consequential load for events resulting the loss of a
single element still inappropriately reaches beyond the reliability of the bulk power system
to local load quality of service issues. The planned and controlled interruption of a small
amount of load, under certain conditions, is not a risk to reliability or an indication of an
unreliable system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

John Mick

Colorado Springs
Utilities

6

Negative

Colorado Springs Utilities ballot on the proposed changes to TPL Table 1, footnote b
directed in FERC Order RM06-16-009 Colorado Springs Utilities wishes to vote NO on the
proposed changes to TPL Table 1, footnote b, directed in FERC Order RM06-16-009. CSU
concurs with the WECC position paper for the ballot, and agrees with the WECC statement
“that the prohibition of loss of non-consequential load for events resulting in the loss of a
single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues”.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.

June 10, 2010

33

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

The SDT agrees that a technical conference on this issue would be of value.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Horace
Stephen
Williamson

Southern Company
Services, Inc.

1

Negative

Richard J.
Mandes

Alabama Power
Company

3

Negative

Anthony L
Wilson

Georgia Power
Company

3

Negative

June 10, 2010

Comments have already been submitted previously, but it will be added here again.
Proposed footnote should read... No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial
Transmission Facilities. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power transfers when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch. It must be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected. The proposed changes are based on the

34

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Gwen S
Frazier

Gulf Power
Company

3

Negative

Don Horsley

Mississippi Power

3

Negative

Michael
Ibold

Xcel Energy, Inc.

3

Negative

Liam
Noailles

Xcel Energy, Inc.

5

Negative

David F.
Lemmons

Xcel Energy, Inc.

6

Negative

George T.
Ballew

Tennessee Valley
Authority

5

Affirmative

Marjorie S.
Parsons

Tennessee Valley
Authority

6

Affirmative

June 10, 2010

Comment
following... “The proposed wording by the drafting team seems to imply that the
curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language
stated only that curtailments were permitted to prepare for the next contingency, not to
address loading related to the initial contingency. The proposed wording could be
interpreted to allow redispatch/firm curtailments to address any single contingency
constraint. Southern Companies recommend that the original language relating to
“preparing for the next contingency” be incorporated into the drafting team’s proposal.”

The proposed modification to footnote b of Table I in TPL-001 - 004 standards states that
after a Category B contingency, there should not be any thermal, voltage or stability
violation, no interruption of firm load (except the load that is directly connected to the
elements that are removed from service as a result of the contingency) and no firm
transfer curtailment (except when coupled with re-dispatch of resources obligated to redispatch). We believe the proposed footnote b creates a gap between TPL-002 and TPL003 standards, since it does not address conditions when firm load shedding and firm
transfer curtailments are not required to meet the system performance for Category B
contingency, but one or both are the required system adjustments to prepare for the next
contingency (Category C3). When firm transfer is curtailed after the first contingency in
preparation for the next contingency, it is not clear from the proposed footnote b if this is
considered a valid system adjustment for Category C or a violation of Category B. Recall
that the existing footnote b addresses this condition explicitly by stating “To prepare for the
next contingency, system adjustments are permitted, including curtailments of contracted
Firm Transfers.”
TVA appreciates the work of the SDT on this issue. However, TVA recommends revising the
second paragraph of the revised footnote b: “To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers. However, curtailment of Firm Transmission Service is
only allowed when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility

35

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
Ratings in those regions should also be respected.” Without the changes in the first two
sentences above, the proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to address any single contingency constraint instead of in
preparation for the next contingency.

Larry Akens

Tennessee Valley
Authority

1

Affirmative

TVA appreciates the work of the SDT. However, TVA recommends revising the second
paragraph of the revised footnote "b". Without changes in the first two sentences, the
proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to
address any single contingency constraint instead of in preparation for the next
contingency.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address
loading issues that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings,
not to bring the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities
may utilize ratings in the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed.
Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial
nd
changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

36

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Robert W.
Roddy

Dairyland Power
Coop.

1

Negative

DPC CONCURS WITH THE MRO COMMENTS.

Jason
Shaver

American
Transmission
Company, LLC

1

Affirmative

For Footnote b, add a third exception to the list, “or (3) end-use load that is either
accepted or volunteered by the customer". It is a widely-held understanding that the
tripping of non-consequential, end-use load is also allowed if the tripping of the load is
either accepted or volunteered by the customer.

Lawrence R.
Larson

Otter Tail Power
Company

1

Negative

The change precludes the use of direct load control systems that should be allowed to
relieve transmission problems. These systems control firm transmission load but rate
conditions can allow their use to mitigate transmission problems.

Response: (Note - MRO did not submit comments with the initial ballot – but did submit the following comment during the formal comment period: For
Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the customer". It is a widely-held
understanding that the tripping of non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered by the
customer in lieu of significant transmission system modifications. )
The SDT has added the fourth bullet to address your concern.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

37

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Ajay Garg

Michael D.
Penstone

Entity

Segment

Vote

Hydro One
Networks, Inc.

1

Negative

Hydro One
Networks, Inc.

3

Comment
Hydro One is casting a negative vote for the following reasons:
1. The amendment to the footnote does not add any technical value to the standard. It
was added only to satisfy a FERC directive to address comments made to allow nonconsequential load loss after a single contingency event, “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to
invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.”

Negative

2. Addressing curtailment of Firm Transmission Service with re-dispatch of resources is a
matter of a commercial nature and should be dealt with in the agreements dealing with
such services. Issues of contracted transmission services, firm or otherwise, are not a
reliability related matter and are not to be dealt with in this standard.
3. Matters of interruption of firm load should be incorporated into this standard only after
the FERC NOPR on the definition of the BES is resolved. As it stands, the footnote will pose
significant problems if the 100 kV and above FERC proposal is applied across the board,
unless the standard specifically states that it applies to the BES as defined by the region
(current definition).

Response: 1. & 2. The SDT disagrees – there is a direct impact on reliability of the BES associated with these concerns. The SDT has added clarity to the
footnote by designating constraints for Demand and firm transfer curtailment.
3. The SDT disagrees that this needs to wait on the FERC NOPR. This standard is applicable to the BES as it is defined.
Spencer
Tacke

Modesto Irrigation
District

4

Negative

I am voting NO vote because of the lack of clarity of the second paragraph of the proposed
change. Although paragraph 1 is an improvement to the current wording, and actually
allows for some specific flexibility in shedding load for an N-1 event, the lack of clarity in
the second paragraph could lead to varied interpretations by members and compliance
auditors. Thank you.

Response: The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

38

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Dana
Cabbell

Southern California
Edison Co.

1

Negative

David
Schiada

Southern California
Edison Co.

3

Negative

Ahmad
Sanati

South California
Edison Company

5

Negative

It is SCE’s position that the planned and controlled interruption of a small amount of load,
under certain conditions, is not a risk to reliability or an indication of an unreliable system,
but rather, serves to preserve the reliability of the bulk power system. Transmission
Planners and Planning Coordinators should be given the discretion to determine whether or
not the planned and controlled interruption of load is an appropriate system response to
certain contingencies, taking into consideration all factors, including customer and local
regulator input, for their individual system. When planned load interruption is identified as
a response to a single event, the impact to the system is often local in nature. The planned
interruption of load may be a desirable alternative to the prohibitive costs associated with a
major new transmission project.
If the NERC Standards Drafting Team decides to proceed with footnote B, as written, it
needs to ensure that Transmission Owners, Transmission Operators, and Transmission
Planners have enough time to both design and implement any mitigation plans necessary
to be compliant with the new language. In almost all cases the actual implementation of a
solution requiring new construction will be dependent on a number of different regulatory
agencies providing the necessary permits allowing for its construction. As such, NERC
needs to ensure that any time frame associated with compliance to the proposed language
be variable, and allow for extended implementation time frames based on system
conditions that may delay placing mitigation plans in service. An example of a reasonable
variable time frame to be compliant with the proposed language in footnote B would be to
start the clock 60 months from receiving the pertinent environmental permitting. In

June 10, 2010

39

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
California this could be the issuance of a Draft Environmental Impact Review pursuant to
the California Environmental Quality Act.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.
The SDT has added more latitude for the Transmission Planner with the addition of the 3rd bullet and believes that 60 months should be sufficient.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

40

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Henry ErnstJr

Entity
Duke Energy
Carolina

June 10, 2010

Segment

Vote

Comment

3

Negative

On the initial ballot of TPL-001-1 Duke Energy also voted “Negative”, primarily because
Duke believes that the requirement prohibiting loss of non-consequential load for P1, P2.1
and P3 events is an overreach by the standard into local load quality of service issues. We
also sought rehearing on the Commission’s March 18 Order Setting Deadline for
Compliance (Docket No. RM06-16), with respect to this and other issues. We believe that
FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of
a single contingency appears to extend beyond measures needed for “reliable operation” of
the bulk-power system to prevent “instability, uncontrolled separation or cascading
failures,” none of which occur when utilities implement a planned and orderly loss of nonconsequential load. Hence, the Commission’s directive to prohibit utilities from
incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that
are needed for “reliable operation” of the bulk-power system as defined under Section 215
of the Federal Power Act. Such directive constitutes an overreaching of the Commission’s
jurisdiction under Section 215 of the Federal Power Act into the jurisdiction of state
commissions which generally have responsibility for overseeing quality of service issues
applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version
of TPL-001-1, it still does not allow Transmission Planners to use appropriate discretion
regarding loss of non-consequential load. Transmission Planners, customers, and local
regulators should jointly control the decision making when BES reliability is not an issue.
Often, the events are extremely improbable and the consequences of these events are local
in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. With this “Negative” vote, Duke
offers the following ideas on alternatives for the SDT to consider that will allow for
appropriate discretion and facilitate proper planning while allowing non-consequential load
loss (NCLL). The standard should allow for dropping of limited amounts of nonconsequential load in situations where it would be reasonable for a bounded time period
and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations
where the near term impact of load projections or implementation of nearby
transmission/generation projects will alleviate the necessity of an upgrade to meet N-1
conditions. Also, reliability of service to end-use customer is impacted by the entire system

41

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
from source to load. Where allowance for NCLL would not greatly impact individual end-use
customers’ level of reliability the transmission planner should consider its use. Normally
transmission system outages are a minor contributor to overall customer outage frequency
and duration. Instances where allowance for NCLL can be used to avoid projects without
greatly impacting a customer’s outage frequency and duration should be acceptable. Use of
reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be considered by the SDT for
determination of acceptable use of NCLL.

Luther E.
Fair

Gainesville
Regional Utilities

1

Affirmative

Even though I am voting in the affirmative, I agree that most of the comments offered by
Duke and Norther Indiana in their earlier statements have merit and should be considered.
Also, I believe that the use of reliability metrics should be considered by the SDT for
determination of acceptable use of NCLL.

Mace Hunter

Lakeland Electric

3

Negative

Reliability should consider the entire system from source to load. Where allowance for
NCLL would not greatly impact individual end-use customer’s level of reliability the
transmission planner should consider its use. Normally transmission system outages are a
minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to delay projects without greatly impacting a customer’s
outage frequency and duration should be acceptable.
Use of reliability metrics should also be considered by the SDT for determination of
acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.
The SDT discussed the use of reliability metrics for providing flexibility to planners but has not included their use as this would make the implementation
too complex.

b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

42

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Sammy
Roberts

Progress Energy
Carolinas

1

Negative

Lee
Schuster

Florida Power
Corporation

3

Negative

Sam Waters

Progress Energy
Carolinas

3

Negative

Wayne

Progress Energy

June 10, 2010

5

Negative

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect
to conditional allowance of curtailing Firm Transmission Service, which is addressed in the
second paragraph of the proposed new footnote (b). PE remains concerned, however, that
the first paragraph of the proposed new footnote (b) does not allow for curtailment of nonradial non-consequential load. The ability to curtail non-consequential load in the planning
horizon can be a useful tool to mitigate local area issues, and has not been detrimental to
the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly
at a localized self-contained level of the system, i.e. the distribution system(s) served by
the Transmission Owner. Prohibiting the curtailment of local load thus constitutes
regulating distribution feeder reliability rather than BES reliability. Events that could be
mitigated through the curtailment of local, non-radial non-consequential load are
infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the
proposed footnote (b) be considered: “No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, and/or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that Load must be interrupted to meet performance requirements only on those
now radial Transmission Facilities, and/or (3) Planned or controlled interruption of any
additional Load required to mitigate the post-contingency results, provided that the non-

43

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Lewis

Entity

Segment

Vote

Carolinas

Comment
consequential load being shed for the event is localized, and provided that the total load
shed for the event does not exceed 2% of the Planned system peak demand or 200 MW,
whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints. The SDT did adopt a limit but felt that 2% of system peak or 200 MW was not equitable for all entities.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Timothy
VanBlaricom

California ISO

2

Negative

The California ISO supports NERC’s request for a public technical conference to be held, as
described in NERC’s April 19, 2010 request for rehearing and motion for stay of the March
18 Order (RM06-16-009), to provide the opportunity to gain industry input and written
comments regarding the Commission’s TPL-002-0 directive for NERC to develop a
modification to the TPL-002-0 Table 1 footnote b.

Response: The SDT agrees that a technical conference would be of value.

June 10, 2010

44

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
The Commission’s directive to prohibit utilities from incorporating carefully controlled loss of
non-consequential load into their planning processes appears to extend the Commission’s
reach beyond its review of measures that are needed for “reliable operation” of the bulkpower system as defined under Section 215 of the Federal Power Act. Such directive
constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the
Federal Power Act into the jurisdiction of state commissions which generally have
responsibility for overseeing quality of service issues applicable to local load. Table B
footnote still does not allow Transmission Planners to use appropriate discretion regarding
loss of non-consequential load. Transmission Planners, and local customers should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. The Commission’s directive sets forth
an expectation that NERC is to implement standards that address all loss of load at costs
that may not be commensurate with bulk power system reliability, as statutorily defined,
which is fundamentally different from what the Reliability Standards were intended to do.

Terry L.
Blackwell

Santee Cooper

1

Negative

Zack
Dusenbury

Santee Cooper

3

Negative

Suzanne
Ritter

Santee Cooper

6

Negative

Response: The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Kimberly J.
Jones

North Carolina
Utilities
Commission

9

Negative

The NC Utilities Commission is concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1, and as explained in draft footnote b,
is an inappropriate overreach into service issues that are more appropriately addressed by
state regulatory commissions. This requirement does not provide any benefit to reliability
of the bulk electric system and could undermine state efforts to balance reliability issues
with cost of service issues. The standard should continue to allow Transmission Planners to
use discretion regarding loss of non-consequential load, understanding that state
commissions are positioned to force electric utilities to address local service quality issues
on an expedited basis, should it be necessary and in the public interest.

Response: The SDT understands the concern but believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES.

June 10, 2010

45

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
James L.
Jones

Entity
Southwest
Transmission
Cooperative, Inc.

Segment

Vote

1

Negative

Comment
THE PROPOSED INTERPRETATION WILL UNDERMINE THE INTERNATIONAL STANDARDS
SETTING PROCESS AND COULD RESULT IN DIFFERING INTERPRETATIONS OF
STANDARDS ON THE NORTH AMERICAN BULK-POWER SYSTEM.

Response: The SDT disagrees and believes that the footnote has been clarified appropriately within the standards development process.
Daryn
Barker

Louisville Gas and
Electric Co.

6

Negative

The revised footnote b on Table 1 imposes additional requirements on the responsible
entities. The footnote states: Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.
However, R1 states: The Planning Authority and Transmission Planner shall each
demonstrate through a valid assessment that its portion of the interconnected transmission
system is planned These statements address different and inconsistent scope. If the
change in scope was intended then a change should also be made to R1 to reconcile the
inconsistency.

Charlie
Martin

Louisville Gas and
Electric Co.

5

Negative

Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions should also be respected. However, R1 states: The
Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned These
statements address different and inconsistent scope. If the change in scope was intended
then a change should also be made to R1 to reconcile the inconsistency.

Response: The SDT agrees that your assessment is for your portion of the interconnected grid. However, when performance in one system is dependent
on generation dispatch in another system or vice versa, the SDT believes that one must ensure that the re-dispatch is feasible. The SDT does not believe
that this presents a conflict with Requirement R1.
John
Apperson

PacifiCorp

June 10, 2010

3

Negative

This proposal warrants a “no” vote due to the current uncertainty regarding the outcome of
the FERC TPL-002 NOPR issued by FERC on March 18, 2010. The impacts of the proposed
changes to footnote B cannot be assessed separately from the alternative interpretation of
TPL-002 proposed by FERC. The proper planning of a transmission system requires that all
performance requirements are known and understood. If only some of the requirements
are known and understood it is impossible to properly plan, study, assess, and operate the
transmission system.

46

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Response: The current TPL-002 is in force and will remain so until the completion of the cited FERC NOPR. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.
Keith V.
Carman

Tri-State G & T
Association Inc.

1

Negative

Tri-State does believe that the new footnote is an improvement, but thinks there are still
some changes necessary. We believe that the word “only” should be removed from the
phrase “...where that Load must be interrupted to meet performance requirements only on
those now radial Transmission Facilities” because that discrimination was not required in
FERC Order RM-06-16-009. There may be times when facilities near the temporary radial
facilities might fall outside the limits set in reliability criteria but the situation is mitigated if
the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State
recommends changing it to "Curtailment of Firm Transmission Service is not allowed unless
it is coupled with curtailment-offsetting resources that are obligated to re-dispatch. Further,
the curtailment activities cannot result in the shedding of any Firm load or in violations of
Facility Ratings, either internal or external to the planning region."
We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of nonconsequential load in the event of a single contingency appears to extend beyond
measures needed for “reliable operation” of the bulk-power system to prevent “instability,
uncontrolled separation or cascading failures,” none of which occur when utilities
implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of nonconsequential load into their planning protocols appears to extend the Commission’s reach
beyond its review of measures that are needed for “reliable operation” of the bulk-power
system as defined under Section 215 of the Federal Power Act. Such directive constitutes
an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for
overseeing quality of service issues applicable to local load.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. Instead of removing the word ‘only’, the 3 bullet has been added to provide the flexibility
requested by industry with appropriate constraints.
nd
The SDT made editorial changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.

June 10, 2010

47

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be constraints
on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Claudiu
Cadar

GDS Associates,
Inc.

1

Negative

We do not agree with the proposed changes due to several reasons. Although the
proposed change will directly influence the reliability standards and transmission system
performances, will also have an indirect impact on the economic side with respect to the
expansion of existing transmission system. We believe that FERC directive as stipulated in
Order 693 cannot constrict, nor impose certain actions outside of the reliability limits. We
believe that since these events are merely isolated and rarely enforced, the decision of
mandating a great financial effort as a consequence of the proposed changes would
certainly be counterbalanced by its feasibility when compare with the current cost of load
shedding. While the revised footnote b can be certainly considered an improvement from
the current version, however it still does not allow the joined entities involved to have
power over the decision making when BES reliability is not an issue.
We also believe that any mandatory changes implemented in the TPL standards under the
current scenario are not entirely feasible unless all other issues such as the definition of the

June 10, 2010

48

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
BES, Consequential / Non-consequential Load, BES Critical Element, etc gets resolve ahead.
The revision with respect to load shedding, specifically the portion about shedding loads on
newly radial facilities, does not match the version 1 TPL standard definition of
consequential load loss. To approve the proposed revision to footnote ‘b’ would create an
unnecessary discrepancy between the version 1 TPL standard under consideration and the
existing standards. We recognize that the Version 1 will replace Version 0, but since it
appears that the performance standard with respect to footnote ‘b’ is intended to be same
in the revised footnote and the Version 1 standard, it only makes sense that the revised
version 0 footnote ‘b’ match the consequential load loss definition contemplated in Version
1.
In the light of the above we suggest the Commission to approach different other solutions
and ideas for improving the current reliability of the transmission system without enforcing
decisions beyond its statutory scope. We advance an alternative to this matter meant to
balance the reliability of the transmission system and its indirect financial impact. Although
the solution that we offer would require an extended time for development and
implementation, however we urge NERC to consider it in its further approach. Our
alternative consists mainly in implementing an additional term such as “Critical Load” which
we have briefly figured that would consist in particular load necessary to be maintained in
service without interruption. Even though this new term would seemed to be at first related
with the quality of the service, however a joint association of transmission planners,
customers, regulatory entities as decision makers can simply individualize the load that
cannot be shed, as well as future transmission improvements that will be required to serve
this envisioned small amount of load rather than the entire load. In this way we will create
a reasonable balance in between the reliability of the transmission system and the cost to
maintain / improve this reliability.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

June 10, 2010

49

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

The current TPL-002 is in force and will remain so for the forseeable future. This limited scope revision to footnote ‘b’ is to add clarity to what is in effect.
Project 2006-02 is under revision and the clarifications of footnote ‘b’ will be considered by the SDT for future revisions of TPL-001-2.
The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the various
industry concerns while assuring BES reliability.
Ronald D.
Schellberg

Idaho Power
Company

1

Negative

While the proposed revisions are an improvement to the prohibition on loss of nonconsequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, that the prohibition of loss of non-consequential load for events resulting the loss of
a single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues.
However, the removal of: "To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers." will require significant adjustments in either TRM or TTC reductions to be
compliant with this revised standard in the WECC Region. To construct additional
transmission facilities to maintain present day business could easily exceed 10 Billion
dollars throughout the WECC region. For example, the Pacific AC Intertie currently has a
TTC of 4800 MW spread across 3 500 kV transmission lines. With the loss of one
Transmission line, the Pacific AC intertie drops to 3200 MW. Removal of this sentence
would require TP either to drop the Firm TTC of the Intertie to 3200, or include a TRM
reservation of at least 1600 MW. The TPs would not be able to say that a loss of 1600 MW
of import capacity would not result in curtailments of firm load. Just about all multi

June 10, 2010

50

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
transmission line paths in the WECC Region would suffer. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. In the case of long
interties between subregions of WECC, these interties have never been planned to operate
in this manner. Idaho Power recommends that the sentence permiting system adjustments
be reinserted into Footnote B.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints.
The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring
the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may
utilize ratings in the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed.
Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made
nd
editorial changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

June 10, 2010

51

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity
o

Segment

Vote

Comment

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Francis J.
Halpin

Bonneville Power
Administration

5

Affirmative

For consistency, regarding the firm transfer issue, the term "Firm Transmission Service"
should be replaced with "Firm Transfers" in order to be consistent with the fourth column
of the existing Table 1 "Transmission System Standards - Normal and Emergency
Conditions".

Response: The SDT agrees and has made the change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Kim Warren

Independent
Electricity System
Operator

June 10, 2010

2

Affirmative

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES
and Firm Demand and on the understanding that the NERC standards apply only to the BES
as defined in the NERC Glossary as follows: “As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with
neighbouring systems, and associated equipment, generally operated at voltages of 100 kV

52

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
or higher. Radial transmission facilities serving only load with one transmission source are
generally not included in this definition.” To be clear, our interpretation of the present
definition of BES is that it defers to each Regional Reliability Organization to define the
elements of the power system that are considered BES and, therefore in the NPCC Region,
"BES as defined by NERC" = "BPS as defined by NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
Jacquie
Smith

ReliabilityFirst
Corporation

10

Affirmative

If this revision is an urgent action, then the implementation timeframe should be shorter.
In the clarification paragraph below, I do not understand the first sentence. Are there
commas missing? What is the requirement and what is the exception?
Also, I question the validity of using “should” in the second sentence. If it is a requirement,
then it needs to be stated as a requirement. If it is a suggestion, then it does not belong in
the standard.
No curtailment of Firm Transmission Service is allowed except when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated
that Facilities remain within applicable Facility Ratings and those adjustments do not result
in the shedding of any firm Load. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.

Response: This has not been classified as an ‘urgent action’.
Commas have been added as appropriate and a re-wording was made which should make this clear.
‘Should’ has been replaced by ‘would’ to provide additional clarity.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels

June 10, 2010

53

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW
o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
David H.
Boguslawski

Northeast Utilities

1

Affirmative

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can
be better defined as the proposed revision is subject to interpretation by the different
entities and regulatory agencies. Future conflicts can be minimized by further clarifying the
proposed revision.
Also, NU is concerned that this new modification does not specify the amount of
permissible load shed nor does it require the planning entity to minimize load shedding
under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
The SDT has modified the footnote for clarity and added constraints in new bullet 3 to address your specific concern.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

54

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Donald S.
Watkins

Bonneville Power
Administration

1

Affirmative

Rebecca
Berdahl

Bonneville Power
Administration

3

Affirmative

Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

Comment
On the firm transfer issues, the term "Firm Transmission Service" should be replaced with
"Firm Transfers" to be consistent with the fourth column of the existing Table 1
Transmission System Standards - Normal and Emergency Conditions.

Response: The SDT agrees and has made this change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Frank
Gaffney

Florida Municipal
Power Agency

4

Affirmative

David
Schumann

Florida Municipal
Power Agency

5

Affirmative

June 10, 2010

Please see FMPA comments submitted through the concurrent comment period for Project
2010-11

55

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Response: Please see the response to FMPA comments above.
Carter B
Edge

SERC Reliability
Corporation

10

Affirmative

The footnote makes clearer when load can be dropped for planning purposes. By making
this footnote more specific, it supports reliability and helps stakeholders apply the TPL
standards.

Timothy
Beyrle

City of New
Smyrna Beach
Utilities
Commission

4

Affirmative

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all
honesty, shedding load for local area impacts has nothing to do with BES reliability and
should not be under FERC jurisdiction under Section 215 of the Federal Power Act, but
rather State jurisdiction for quality of service issues. However, there is also the matter of
FERC jurisdiction over commercial matters and the opportunity to “game” the original
footnote by transmission providers by allowing firm load shedding to grant firm
transmission service for themselves, thereby avoiding or deferring transmission investment,
while at the same time denying or requiring others to build the same transmission avoided
in order to obtain transmission service. We can see how difficult it is from a drafting team’s
perspective in achieving a balanced position between these different matters. The drafting
team should be applauded for finding a reasonable position.

1

Affirmative

This issue is better handled within the development of the new TPL-001 standard.

Response: Thank you for your support.
Larry E Watt

Lakeland Electric

Response: The current TPL-002 is in force and will remain so until the completion of the TPL-001-2 effort. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.

June 10, 2010

56

Consideration of Comments on Project 2010-11: TPL Table 1 Order and
Comments Submitted with Initial Ballots
The Standards Committee thanks all commenters who submitted comments on the
proposed SAR for the TPL Table 1 Order. The SAR proposed changes to TPL Table 1 in
response to FERC’s Order RM06-16-009 which required the ERO to clarify TPL-002-0, Table
1 - footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single contingency occurs on a transmission system. Such clarification was originally
required by June 30, 2010. Table 1 is used in TPL-001, TPL-002, TPL-003, and TPL-004 –
and any change to Table 1 needs to be reflected in all four of these TPL standards. (Note:
FERC issued a clarifying order on June 11, 2010 which extended the deadline for clarifying
Table 1 until March 31, 2011.)
The SAR, implementation plan, and the clean and redline versions to the four TPL standards
were posted for a 40-day public comment period from April 15, 2010 through May 27, 2010.
Stakeholders were asked to provide feedback on the standards through a special electronic
comment form. There were 22 sets of comments, including comments from more than 80
different people from approximately 40 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.
The initial ballot for the proposed changes to the four TPL standards was conducted from
May 17-27, 2010. The comments submitted with initial ballots and the drafting team’s
responses to those comments are contained in this report.
All comments submitted during the comment period and the initial ballot results are posted
on the following page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Based on stakeholder comments, the drafting team has made some additional changes to
Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes include
the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the
terminology used in the associated column heading of Table 1 – ‘Loss of Demand or
Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology
changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear
to the SDT from the cited inputs that there were still a number of concerns with the
proposed clarification. In particular, entities were concerned that the proposal was still
unclear and too limiting on the proposed conditions when load could be interrupted. Also,
there were numerous concerns raised on jurisdictional issues with regard to interrupting
Demand. In short, the needed clarification hadn’t been achieved. Therefore, the SDT
continued discussions on different alternatives to address the needed clarification. This led
the SDT to focus on identifying constraining parameters such as the amount of Demand that
could be interrupted, annual amount of exposure, etc.

In order to receive additional industry feedback on the new approach, a Technical
Conference was held on August 10, 2010 to address four specific questions arising from the
FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to
plan to shed non-consequential firm load for a single contingency (Category B)? Please
provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be applied at the fringes of a system.
Is this limitation appropriate and if so, please define it? What other specific criteria
could be applied to limit the planned use of non-consequential firm load loss for a single
contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B), what
changes to your transmission plan would be required? Please quantify your response to
the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be handled on a case-by-case basis
with affected entities asking for an exception from the ERO. Could you support such a
process? If your response is no, then what process would you suggest? If your
response is yes, then what technical criteria should be developed to identify and
evaluate cases?
In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand is appropriate in certain
limited circumstances and that such usage is not widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’
could possibly be discriminatory.



If interruption of non-consequential Demand were not allowed, such a policy would
result in significant costs to customers for limited benefits.



A case-by-case exception process that requires ERO or FERC approval was not
viewed as an acceptable approach due to possible inconsistencies in approach and
potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to
leverage the existing work with the industry comments to develop an acceptable clarification
to footnote ‘b’. This led to the approach shown in the 2nd posting where the SDT has taken
the concept of allowing interruption of Demand without numerical constraints in an open
and transparent stakeholder process to review and accept such plans. This open and
transparent stakeholder process is seen as an enhancement of existing entity processes
without the problems associated with an ERO or FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693
directives (and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an
equal and effective method and that should be acceptable to all concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always
acceptable to use Interruptible Demand and Demand-Side Management:


Interruptible Demand or Demand-Side Management

The above changes will be noted to stakeholders in a separate posting before the initiation
of another ballot.
The revised Footnote ‘b’ is:

b) An objective of the planning process is to avoid interruption of Demand. Interruption
of Demand is discouraged and measures to mitigate such interruption should be
pursued within the planning process. However, Demand may need to be interrupted in
limited circumstances to address BES performance requirements. When interruption
of Demand is utilized within the planning process, such interruption is limited to:


Demand that is directly served by the elements that are removed from service as
a result of the Contingency



Interruptible Demand or Demand-Side Management



Demand that does not adversely impact overall BES reliability where the
circumstances describing the use of such Demand interruption are documented,
including alternatives evaluated; and where the application is subject to review
and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions would also be
respected.

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected] In addition, there is
a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Comments and Responses from Formal Comment Period: 
1. 

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system by June 30, 2010. Do you agree with the proposed changes and if not, please provide specific
reasons for your disagreement. .......................................................................................................................... 10 

2. 

Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any regulatory function,
rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the conflict. .................................. 25

Comments and Responses from Initial Ballot: 
3. 

Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010 ..................................... 30 

August 30, 2010

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Commenter

Organization

Industry Segment
1

1.

Group

Guy Zito
Additional Member

2

3

4

5

6

8

9

10

Northeast Power Coordinating Council

X

Additional Organization

Region

Segment Selection

1. Alan Adamson

New York State Reliability Council

NPCC

10

2. Greg Campoli

New York Independent System Operator

NPCC

2

3. Roger Champagne

Hydro-Quebec TransEnergie

NPCC

2

4. Kurtis Chong

Independent Electricity System Operator

NPCC

2

5. Sylvain Clermont

Hydro-Quebec TransEnergie

6. Chris de Graffenried

Consolidated Edison Co. of New York, Inc.

NPCC

1

7. Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

8. Ben Eng

New York Power Authority

NPCC

4

9. Brian Evans-Mongeon

Utility Services

NPCC

8

10. Mike Garton

Dominion Resources Services, Inc.

NPCC

5

11. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

12. Kathleen Goodman

ISO - New England

NPCC

2

13. David Kiguel

Hydro One Networks Inc.

NPCC

1

14. Peter Yost

Consolidated Edison Co. of New York, Inc.

NPCC

3

August 30, 2010

7

1

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6

15. Randy MacDonald

New Brunswick System Operator

NPCC

2

16. Bruce Metruck

New York Power Authority

NPCC

6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18. Robert Pellegrini

The United Illuminating Company

NPCC

1

19. Saurabh Saksena

National Grid

NPCC

1

20. Michael Schiavone

National Grid

NPCC

1

2.

South Carolina Electric & Gas

Group

Philip R. Kleckley
Additional Member

X

Additional Organization

X
Region

Southern Company Services - Trans.

SERC

1

Tennessee Valley Authority

SERC

1

3. Charles Long

Entergy

SERC

1

4. James Manning

North Carolina Electric Membership Corporation

SERC

3

5. Pat Huntley

SERC Reliability Corporation

SERC

10

John Bee

Exelon Transmission Strategy & Compliance

Additional Member

X

Additional Organization

X
Region

Segment Selection

:(ComEd)

RFC

1

2. Weaver, David W

(PECO)

RFC

1

3. McHugh, Kathleen P

(PECO)

RFC

1

4. Kay, Thomas W

(ComEd)

RFC

1

5. Szymczak, Ronald

(ComEd)

RFC

1

6. Chu, Ron F

(PECO)

RFC

1

7. Donnelly, Michael J

(PECO)

RFC

1

8. Kliros, Chris B

(ComEd)

RFC

1

9. Mills, Paul M

(ComEd)

RFC

1

10. Webb, Becky

(ComEd)

RFC

1

Group

Denise Koehn

August 30, 2010

BPA, Transmission Reliability Program

X

X

10

X

1. Mortenson, Eric

4.

9

Segment Selection

2. David Marler

Group

8

X

1. Bob Jones

3.

7

X

X

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

Additional Member

2

Additional Organization

3

4

5

6

Region

BPA, Transmission Planning

WECC

1

2. Berhanu Tesema

BPA, Transmission Planning

WECC

1

3. Larry Furumasu

BPA, Transmission Planning

WECC

1

4. Kyle Kohne

BPA, Transmission Planning

WECC

1

5. Don Watkins

BPA, Transmission System Operations

WECC

1

6. Rebecca Berdahl

BPA, Power, Long Term Sales and Purchases

WECC

3

Group

Carol Gerou
Additional Member

Additional Organization

Region

Segment Selection

MRO

1

2. Tom Webb

Wisconsin Public Service

MRO

3, 4, 5, 6

3. Terry Bilke

Midwest ISO Inc.

MRO

2

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

7. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

8. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

Richard Kafka

Pepco Holdings, Inc.

Additional Member

X

X

Additional Organization

X

X

Region

Segment Selection

1. Jim Summers

Delmarva Power and Light Co.

RFC

1

2. John Radman

Potomac Electric Power Company

RFC

1

7.

Group

Ben Li
Additional Member

August 30, 2010

10

X

American Transmission Company

Group

9

Midwest Reliability Organization

1. Chuck Lawrence

6.

8

Segment Selection

1. Chuck Matthews

5.

7

IESO

X
Additional Organization

Region

Segment Selection

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

1. Bill Phillips

MISO

MRO

2. James Castle

NYISO

NPCC

3. Charles Yeung

SPP

SPP

4. Lourdes Estrada-Salinero

CAISO

WECC

5. Patrick Brown

PJM

RFC

6. Steve Myers

ERCOT

ERCOT

8.

Group

Frank Gaffney

Florida Municipal Power Agency

Additional Member

2

3

X

Additional Organization

4

5

6

X

X

X

Region

Utilities Commission of New Smyrna Beach

FRCC

4

2. Greg Woessner

Kissimmee Utility Authority

FRCC

1

3. Jim Howard

Lakeland Electric

FRCC

1

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services

FRCC

1

6. Cairo Vanegas

Fort Pierce Utility Authority

FRCC

4

Individual

Stephen Mizelle

Southern Company Transmission

X

Robert Casey

Georgia Transmission Corporation (Bulk
System Planning)

X

Individual
11.

Individual

Thad Ness

American Electric Power

X

X

X

X

12.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

13.

Individual

Martin Bauer

US Bureau of Reclamation

14.

Individual

Kirit Shah

Ameren

X

X

X

15.

Individual

Robert W. Roddy

Dairyland Power Cooperative

X

X

X

10.

August 30, 2010

8

9

10

Segment Selection

1. Timothy Beyrle

9.

7

X
X

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6
X

16.

Individual

Marty Berland

Progress Energy

X

X

X

17.

Individual

Michael R. Lombardi

Northeast Utilities

X

X

X

18.

Individual

Charles Lawrence

American Transmission Company

X

19.

Individual

Greg Rowland

Duke Energy

X

X

X

X

X

X

X

Bill Middaugh

Tri-State Generation and Transmission
Association, Inc.

X

Individual
21.

Individual

Roger Champagne

Hydro-Québec TransEnergie (HQT)

X

22.

Individual

Dan Rochester

Independent Electricity System Operator

20.

August 30, 2010

7

8

9

10

X

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which
required the ERO to clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system by June 30, 2010. Do you agree with the proposed
changes and if not, please provide specific reasons for your disagreement.
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made
changes to the footnote to balance the various industry concerns while assuring BES reliability.
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology used in the associated column heading of Table 1 –
‘Loss of Demand or Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the SDT from the cited inputs that there were still a
number of concerns with the proposed clarification. In particular, entities were concerned that the proposal was still unclear and too limiting on the
proposed conditions when load could be interrupted. Also, there were numerous concerns raised on jurisdictional issues with regard to
interrupting Demand. In short, the needed clarification hadn’t been achieved. Therefore, the SDT continued discussions on different alternatives
to address the needed clarification. This led the SDT to focus on identifying constraining parameters such as the amount of Demand that could be
interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference was held on August 10, 2010 to address four
specific questions arising from the FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to plan to shed non-consequential firm load for a single
contingency (Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency (Category B) could be
applied at the fringes of a system. Is this limitation appropriate and if so, please define it? What other specific criteria could be applied to limit
the planned use of non-consequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of non-consequential firm load allowed for a single contingency event
(Category B), what changes to your transmission plan would be required? Please quantify your response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency (Category B) could be
handled on a case-by-case basis with affected entities asking for an exception from the ERO. Could you support such a process? If your
response is no, then what process would you suggest? If your response is yes, then what technical criteria should be developed to identify
and evaluate cases?

August 30, 2010

10

Consideration of Comments on TPL Table 1 Order — Project 2010-11

In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand was appropriate in certain limited circumstances and that such usage was not
widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could possibly be discriminatory.



If interruption of non-consequential Demand was not allowed, such a policy would result in significant costs to customers for limited benefits.



A case-by-case exception process that required ERO or FERC approval was not viewed as an acceptable approach due to possible
inconsistencies in approach and potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the existing work with the industry comments to
develop an acceptable clarification to footnote ‘b’. This led to the approach shown in this 2nd posting where the SDT has taken the concept of
allowing interruption of Demand without numerical constraints in an open and transparent stakeholder process to review and accept such plans.
This open and transparent stakeholder process is seen as an enhancement of existing entity processes without the problems associated with an
ERO or FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives (and subsequent orders) concerning
clarification to footnote ‘b’ in a way that is an equal and effective method and that should be acceptable to all concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable to use Interruptible Demand and Demand-Side
Management:


Interruptible Demand or Demand-Side Management

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:




(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
Interruptible Demand or Demand-Side Management
(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial

August 30, 2010

11

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization

Yes or No

Question 1 Comment

Duke Energy

No

Duke Energy voted "Negative" on the initial and current ballots of TPL-001-1, primarily because Duke believes
that the requirement prohibiting loss of non-consequential load for P1, P2.1 and P3 events is an overreach by
the standard into local load quality of service issues. We also sought rehearing on the Commission’s March
18 Order Setting Deadline for Compliance (Docket No. RM06-16), with respect to this and other issues. We
believe that FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of a
single contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power
system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many instances, it may be in the
best interest of all involved parties from an overall cost/benefit point of view to allow loss of non-consequential
load.
Duke offers the following ideas on alternatives for the SDT to consider that will allow for appropriate discretion
and facilitate proper planning while allowing non-consequential load loss (NCLL).The standard should allow
for dropping of limited amounts of non-consequential load in situations where it would be reasonable for a

August 30, 2010

12

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
bounded time period and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations where the near term
impact of load projections or implementation of nearby transmission/generation projects will alleviate the
necessity of an upgrade to meet N-1 conditions. Also, reliability of service to end-use customer is impacted by
the entire system from source to load. Where allowance for NCLL would not greatly impact individual enduse customers’ level of reliability the transmission planner should consider its use. Normally transmission
system outages are a minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to avoid projects without greatly impacting a customer’s outage frequency
and duration should be acceptable. Use of reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be
considered by the SDT for determination of acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Midwest Reliability Organization

August 30, 2010

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by

13

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Dairyland Power Cooperative

No

DPC concurs with the MRO comments: For Footnote b, add a third exception to the list, "or (3) end-use load
that is either accepted or volunteered by the customer". It is a widely-held understanding that the tripping of
non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered
by the customer in lieu of significant transmission system modifications.

American Transmission
Company

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Response: The SDT has added the second bullet to address your concern.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

August 30, 2010

14

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Georgia Transmission
Corporation (Bulk System
Planning)

Yes or No

Question 1 Comment

No

Georgia Transmission Corporation (GTC) believes that the requirement prohibiting loss of non-consequential
load for P1, P2.1 and P3 events is an overreach by the standard into local load quality of service issues. We
believe that FERC’s directive in (Docket No. RM06-16) to prohibit the loss of non-consequential load in the
event of a single contingency appears to extend beyond measures needed for “reliable operation” of the bulkpower system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the cost of major projects. In
many instances, it may be in the best interest of all involved parties from an overall cost/benefit point of view
to allow loss of non-consequential load.
We also note that on April 19 NERC filed a request for rehearing with FERC asking that the Commission
revise the directive in Paragraph 8 of the March 18 TPL-002 Order to allow NERC the necessary time to
incorporate changes to the TPL-002 Reliability Standard through the Reliability Standards Development
Process that are necessary to achieve bulk power system reliability. NERC also requested that the
Commission grant NERC’s Motion for Stay to stay the Order so that a public technical conference with
opportunity for comment can be held in order to provide parties an opportunity to meet and discuss the
technical considerations of developing a modification to the TPL-002 standard that prohibits the loss of nonconsequential firm load in the event of an N-1 contingency. NERC’s April 19 filing pointed out that if the
Commission’s directive to disallow the loss of non-consequential firm load for an N-1 contingency is
implemented, a question is presented regarding whether the Reliability Standard still serves the purpose of
ensuring the Reliable Operation of the bulk power system by preventing instability, uncontrolled separation,
and cascading failures. That is, the Commission’s directive sets forth an expectation that NERC is to
implement standards that address all loss of load at costs that may not be commensurate with bulk power
system reliability, as statutorily defined, which is fundamentally different from what the Reliability Standards
were intended to do.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the

August 30, 2010

15

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

various industry concerns while assuring BES reliability. .
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Progress Energy

August 30, 2010

No

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect to conditional
allowance of curtailing Firm Transmission Service, which is addressed in the second paragraph of the
proposed new footnote (b). PE remains concerned, however, that the first paragraph of the proposed new
footnote (b) does not allow for curtailment of non-radial non-consequential load. The ability to curtail nonconsequential load in the planning horizon can be a useful tool to mitigate local area issues, and has not been
detrimental to the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly at a localized selfcontained level of the system, i.e. the distribution system(s) served by the Transmission Owner/Operator.
Prohibiting the curtailment of local load thus constitutes regulating distribution feeder reliability rather than
BES reliability. Events that could be mitigated through the curtailment of local, non-radial non-consequential
load are infrequent, and such curtailment has no material effect on the reliability of the BES.

16

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
PE therefore suggests that the following addition (item (3)) to the first paragraph of the proposed footnote (b)
be considered:”No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served
by the elements that are removed from service as a result of the Contingency, and/or (2) Planned or
controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now
radial Transmission Facilities, and/or (3) Planned or controlled interruption of any additional Load required to
mitigate the post-contingency results, provided that the non-consequential load being shed for the event is
localized, and provided that the total load shed for the event does not exceed 2% of the Planned system peak
demand or 200 MW, whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
various industry concerns while assuring BES reliability. The SDT did not adopt numerical limits as a single nation-wide value was not seen as equitable for all
entities.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Hydro-Québec TransEnergie

August 30, 2010

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

(HQT)

Question 1 Comment
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Northeast Power Coordinating
Council

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Response: The SDT believes that it has been responsive to the FERC directive in that the standards development process has been employed. In the
development of the footnote, the SDT has balanced the need for discretion while addressing local area concerns with the need to assure the reliability of the BES.

August 30, 2010

18

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

‘Must’ is not appropriate in a footnote as it would impose a requirement in the footnote. The SDT has replaced ‘should’ with ‘would’ to correct the grammar.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Tri-State Generation and
Transmission Association, Inc.

No

Tri-State does believe that the new footnote is an improvement, but thinks there are still some changes
necessary. We believe that the word “only” should be removed from the phrase “...where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities” because that
discrimination was not required in FERC Order RM-06-16-009. There may be times when facilities near the
temporary radial facilities might also fall outside the limits set in reliability criteria but the situation is mitigated
if the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State recommends changing it to
"Curtailment of Firm Transmission Service is not allowed unless it is coupled with curtailment-offsetting
resources that are obligated to re-dispatch. Further, the curtailment activities cannot result in the shedding of
any Firm load or in violations of Facility Ratings, either internal or external to the planning region."

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the

August 30, 2010

19

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

various industry concerns while assuring BES reliability.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Southern Company Transmission

No

We propose that the section in double parentheses be deleted. The proposed wording by the drafting team
seems to imply that the curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language stated only that
curtailments were permitted to prepare for the next contingency, not to address loading related to the initial
contingency. The proposed wording could be interpreted to allow redispatch/firm curtailments to address any
single contingency constraint.
Southern Companies recommend that the original language relating to “preparing for the next contingency” be
incorporated into the drafting team’s proposal.((Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted element or by the
affected area, may occur in certain areas without impacting the overall reliability of the interconnected
transmission systems. To prepare for the next contingency, system adjustments are permitted, including

August 30, 2010

20

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
curtailments of contracted Firm (non-recallable reserved) electric power Transfers.)) No interruption of firm
Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities. To prepare
for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (nonrecallable reserved) electric power transfers No curtailment of Firm Transmission Service is allowed except
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch. where it can It must be
demonstrated that Facilities remain within applicable Facility Ratings and those adjustments do not result in
the shedding of any firm Load. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions should also be respected.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the
Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in
the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity is obligated to re-dispatch
its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the
affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words
“To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your
comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

August 30, 2010

21

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
South Carolina Electric & Gas

Yes

For better clarity delete the phrase “when coupled with” in the second paragraph of footnote ‘b.’

Response: The SDT did not delete the suggested phrase as it believes it is correct as stated but added commas to make the phrase read more clearly.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Independent Electricity System
Operator

August 30, 2010

Yes

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES and Firm Demand
and on the understanding that the NERC standards apply only to the BES as defined in the NERC Glossary
as follows:”As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally operated
at voltages of 100 kV or higher. Radial transmission facilities serving only load with one transmission source
are generally not included in this definition.” To be clear, our interpretation of the present definition of BES is

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
that it defers to each Regional Reliability Organization to define the elements of the power system that are
considered BES and, therefore in the NPCC Region, "BES as defined by NERC" = "BPS as defined by
NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
BPA, Transmission Reliability
Program

Yes

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with "Firm Transfers" to
be consistent with the fourth column of the existing Table 1 Transmission System Standards - Normal and
Emergency Conditions.

Response: The SDT agrees and has made the change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
American Electric Power

August 30, 2010

Yes

23

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Exelon Transmission Strategy &
Compliance

Yes

Florida Municipal Power Agency

Yes

IESO

Yes

Northeast Utilities

Yes

Pepco Holdings, Inc.

Yes

US Bureau of Reclamation

Yes

Manitoba Hydro

Yes

MH agrees with the SDT proposal.

Ameren

Yes

We were ok with the previous language. Though we do not intend to drop non-consequential load for a single
contingency, we undersatnd that other ares may have been following such practice without degarding the
relaibility of BES. We believe that they can continue this practice if they develop non-firm contracts with these
customers.

Response: Thank you for your support. Several stakeholders proposed additional modifications and the drafting team did make several additional modifications to
the footnote – please see the revised footnote.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

2. Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the
conflict.
Summary Consideration: The SDT understands that there may be conflicts as pointed out by respondents; however, the SDT believes that
there should be constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES. Strict
numerical constraints applied across all of North America were not seen as appropriate. Instead, the SDT is leveraging existing processes to
require documentation of Demand to be interrupted including alternatives evaluated and for the situation to be vetted in an open and transparent
stakeholder process.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
Interruptible Demand or Demand-Side Management

o
o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization
Ameren

Yes or No

Question 2 Comment

No

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

American Electric Power

No

American Transmission
Company

No

BPA, Transmission Reliability
Program

No

Dairyland Power Cooperative

No

Exelon Transmission Strategy &
Compliance

No

Independent Electricity System
Operator

No

Manitoba Hydro

No

Midwest Reliability Organization

No

Southern Company Transmission

No

US Bureau of Reclamation

No

South Carolina Electric & Gas

No

Question 2 Comment

The comments expressed herein represent a consensus of the views of the above named members of the
SERC Engineering Committee Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.

Response: Thank you for your response. Several stakeholders proposed additional modifications and the drafting team did make several additional modifications
to the footnote – please see the revised footnote.
Hydro-Québec TransEnergie
(HQT)

August 30, 2010

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment
between state and federal positions could place utilities in a compromising position.

Northeast Power Coordinating
Council

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

IESO

Yes

It should be noted that conflicts may arise between individual state commissions, who may have rate recovery
authority, and utilities who attempt to abide explicitly with FERC’s position on non-consequential load loss. In
RM-06-16-009, the Commission again references Order 693 and specifically highlights comments by Duke
Power Company and Northern Indiana Public Service Company by saying the arguments made to date to
allow non-consequential load loss after a single contingency event is “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to invest in the bulk
electric system to the point that it can continue service to all firm load customers under some specific N-1
scenarios.” In the US, State commissions with rate recovery authority may take the position that considering
the economics of proposed investments intended to prevent non-consequential loss of small or remote load is
acceptable. This potential conflict between state and federal positions could place utilities in a compromising
position.Similar conflicts may also exist in Canada.

Progress Energy

Yes

There is the potential for conflict between Table 1 - Footnote (b) as currently proposed, which can be
considered to regulate local distribution reliability without improving BES reliability, and local service reliability
issues which are under the purview of state regulatory agencies. For example, the North Carolina Utilities
Commission (NCUC) commented regarding this concern in the ballot which ended March 1 in Project 200602. Specifically, NCUC commented that they were “...concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1 is an inappropriate overreach into service issues that
are more appropriately addressed by state regulatory commissions...” Progress Energy believes that NCUC’s
concerns are legitimate. BES reliability should address the avoidance and mitigation of cascading outages
and BES facility damage, rather than limited, controlled local area loss of load, in order to avoid this conflict
and overlap of regulation.

Response: The SDT understands the issue; however, the SDT believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES. Strict numerical constraints applied across all of North America were not seen as appropriate. Instead, the SDT
is leveraging existing processes to require documentation of Demand to be interrupted including alternatives evaluated and for the situation to be vetted in an
open and transparent stakeholder process.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Northeast Utilities

Yes or No

Question 2 Comment

Yes

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can be better defined as
the proposed revision is subject to interpretation by the different entities and regulatory agencies. Future
conflicts can be minimized by further clarifying the proposed revision.
Also, NU is concerned that this new modification does not specify the amount of permissible load shed nor
does it require the planning entity to minimize load shedding under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Duke Energy

Yes

See response to question #1.

Georgia Transmission
Corporation (Bulk System
Planning)

Yes

See response to Question #1.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

Response: See response to question #1.
Florida Municipal Power Agency

Yes

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all honesty, shedding load
for local area impacts has nothing to do with BES reliability and should not be under FERC jurisdiction under
Section 215 of the Federal Power Act, but rather State jurisdiction for quality of service issues. However,
there is also the matter of FERC jurisdiction over commercial matters and the opportunity to “game” the
original footnote by transmission providers by allowing firm load shedding to grant firm transmission service
for themselves, thereby avoiding or deferring transmission investment, while at the same time denying or
requiring others to build the same transmission avoided in order to obtain transmission service. We can see
how difficult it is from a drafting team’s perspective in achieving a balanced position between these different
matters. The drafting team should be applauded for finding a reasonable position.

Pepco Holdings, Inc.

Yes

This is not an issue for historic PJM members, but as PJM has expanded and as a result of the merger of
historic councils into RFC, I am aware that not all regions had standards equal to those of MAAC, and this
has been an issue worked out between transmission planners (historic transmission owners) and their local
regulators. It is ultimately a cost issue for loss of local load that does not affect the overall reliability of the
interconnected BES.

Yes

We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of non-consequential load
in the event of a single contingency appears to extend beyond measures needed for “reliable operation” of the
bulk-power system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur
when utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their
planning protocols appears to extend the Commission’s reach beyond its review of measures that are needed
for “reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act.
Such directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal
Power Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality
of service issues applicable to local load.

Response: Thank you for your support.
Tri-State Generation and
Transmission Association, Inc.

Response: The SDT is not in a position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES. Such constraints would be determined
through the open and transparent stakeholder process.

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

3. Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made changes to
the footnote to balance the various industry concerns while assuring BES reliability.
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology used in the associated column
heading of Table 1 – ‘Loss of Demand or Curtailed Firm Transfers.’ For additional clarity, the team made the following
terminology changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the SDT from the cited inputs that
there were still a number of concerns with the proposed clarification. In particular, entities were concerned that the proposal
was still unclear and too limiting on the proposed conditions when load could be interrupted. Also, there were numerous
concerns raised on jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t been
achieved. Therefore, the SDT continued discussions on different alternatives to address the needed clarification. This led the
SDT to focus on identifying constraining parameters such as the amount of Demand that could be interrupted, annual amount
of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference was held on August 10, 2010 to
address four specific questions arising from the FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to plan to shed non-consequential firm
load for a single contingency (Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency
(Category B) could be applied at the fringes of a system. Is this limitation appropriate and if so, please define it? What
other specific criteria could be applied to limit the planned use of non-consequential firm load loss for a single contingency
(Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of non-consequential firm load allowed for a single
contingency event (Category B), what changes to your transmission plan would be required? Please quantify your response
to the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency
(Category B) could be handled on a case-by-case basis with affected entities asking for an exception from the ERO. Could

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

you support such a process? If your response is no, then what process would you suggest? If your response is yes, then
what technical criteria should be developed to identify and evaluate cases?
In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand was appropriate in certain limited circumstances and that such
usage was not widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could possibly be discriminatory.



If interruption of non-consequential Demand was not allowed, such a policy would result in significant costs to customers for
limited benefits.



A case-by-case exception process that required ERO or FERC approval was not viewed as an acceptable approach due to
possible inconsistencies in approach and potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the existing work with the
industry comments to develop an acceptable clarification to footnote ‘b’. This led to the approach shown in this 2nd posting
where the SDT has taken the concept of allowing interruption of Demand without numerical constraints in an open and
transparent stakeholder process to review and accept such plans. This open and transparent stakeholder process is seen as an
enhancement of existing entity processes without the problems associated with an ERO or FERC case-by-case exception
process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives (and subsequent orders)
concerning clarification to footnote ‘b’ in a way that is an equal and effective method and that likely will be acceptable to all
concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable to use Interruptible Demand
and Demand-Side Management:


Interruptible Demand or Demand-Side Management

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:

August 30, 2010

31

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

o (1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
o Interruptible Demand or Demand-Side Management
o (2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Voter
Rodney
Phillips

Entity
Allegheny Power

Segment

Vote

Comment

1

Negative

Allegheny Power believes the loss of non-consequential load and/or curtailment of
transmission service for N-1 contingencies should be limited to only extreme circumstances.
Exception 2 of footnote b allows for the loss of non-consequential load for N-1
contingencies with no restriction. Allegheny Power recommends removing exception 2
footnote b.

Response: The SDT and the majority of the commenters disagree with this suggestion.
Gordon
Rawlings

BC Transmission
Corporation

1

Negative

Faramarz
Amjadi

BC Transmission
Corporation

2

Negative

Hubert C.
Young

South Carolina
Electric & Gas Co.

3

Negative

August 30, 2010

BCTC appreciates the good work of the SAR committee in drafting the changes to Footnote
b of Table 1. BCTC agrees with the drafting team that interruption of firm load, served by
either radial circuits or circuits that have became radial as a result of the contingency,
should be allowed for N-1 contingencies. However, it is our position that interruption of
firm load should not be limited only to such consequential loads. In our view, interruption
of electric supply to some local network customers in the affected area should be
permissible. This inclusion will allow transmission planners to plan BCTC’s regional
transmission network reliably and without impacting neighbouring transmission networks.
SCE&G has significant concern with the proposed revision to TPL Table 1, Footnote B. The
current Footnote B states “Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted

32

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the
overall reliability of the interconnected transmission systems” is important to the TPL
standards to ensure that ERO standards do not dictate the level of service to customers.
Service to customers and load pockets is jurisdictional to State Commissions and ERO
standards should not compromise this jurisdiction. SCE&G believes that any proposed
revisions to Footnote B must retain the concept that planned or controlled interruption of
electric supply to customers, whether they are radial or network, is allowed as long as it
does not impact the overall reliability of the interconnected transmission systems. The
proposed revision eliminates this concept. There seems to be a general inconsistency and
maybe confusion between the terms “reliability” and “level of service”.

David Frank
Ronk

Consumers Energy

4

Negative

James B
Lewis

Consumers Energy

5

Negative

Hugh A.
Owen

Public Utility
District No. 1 of
Chelan County

6

Negative

The interruption of a small amount of load is, under most conditions, not a risk to the
reliability of the BES and is at times necessary to preserve reliability. The planned
interruption of some load may be a cost effective alternative to a costly transmission
project. That is a quality of service issue.

Michael
Gammon

Kansas City Power
& Light Co.

1

Negative

Charles
Locke

Kansas City Power
& Light Co.

3

Negative

Thomas
Saitta

Kansas City Power
& Light Co.

6

Negative

While the current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the recently balloted version of TPL-001-1, it still does
not allow Transmission Planners to use appropriate discretion regarding loss of nonconsequential load. Transmission Planners, customers, and local regulators should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit

August 30, 2010

The current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the previous version of TPL-001-1. However, it still does
not allow Transmission Planners to use appropriate and necessary discretion regarding loss
of non-consequential load. Transmission Planners, customers, and local regulators should
control the decision making when BES reliability is not an issue. Often, the consequences of
these events are solely local in nature, requiring only minor additional loss of local load to
avoid the costly major projects. In many instances, it may be in the best interest of all
involved parties from an overall cost/benefit point of view to allow loss of nonconsequential load.

33

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
point of view to allow loss of non-consequential load.

Linda Brown

San Diego Gas &
Electric

1

Affirmative

As to item (1), all load served directly by a transmission element which experiences a fault
will be interrupted when the faulted element is taken out of service. This is the natural
relationship between the load and the transmission element. Allowing this for BES elements
may encourage transmission owners to remove transmission instead of upgrading or
replacing it. Consider a load supplied by two transmission lines of different capacity. If the
larger line is lost due to a contingency (N-1) and the remaining smaller line overloads the
transmission owner is left with several options to address the problem: (1) move load
between buses, (2) upgrade the smaller line, (3) add another line, or (4) create a radial
load by removing the smaller line. Number (4) may be the least expensive and allowable
under TPL-002, footnote b.
Item (2) may also encourage transmission owners to develop plans which make load
shedding part of category B. Consider a load served by three transmission lines, a utility
may decide to remove a line, instead of upgrading, in order to set up a situation where an
N-1 contingency would make the bus temporarily radial. In the event of a single outage (N1), the load bus will be temporarily radial and load can be shed at the bus.

W. R.
Schoneck

Florida Power &
Light Co.

3

Affirmative

I believe the language is an improvement and clarifies the intent but I believe there still
should be additional language added to give an exemption in meeting this requirement if it
does not make economic sense(not economically feasible) and has no real impact on the
BES.

Richard J
Kafka

Potomac Electric
Power Co.

1

Affirmative

It is understood that this is a compliance filing issue. This is not an issue for historic PJM
members, but as PJM has expanded and as a result of the merger of historic councils into
RFC, I am aware that not all regions had standards equal to those of MAAC, and this has
been an issue worked out between transmission planners (historic transmission owners)
and their local regulators. It is ultimately a cost issue for loss of local load that does not
affect the overall reliability of the interconnected BES.

Alan Gale

City of Tallahassee

5

Affirmative

TAL thanks for SDT for the tireless effort to get to this point. TAL is voting affirmative with
the following comments. We accept that the loss of non-consequential load is not a desired
result for N-1 contingencies. It is also not the norm in system planning or operations. The
flexibility to operate the system consistent with “good utility practice” may warrant the
“odd-ball” case that would require this to occur. The dropping of non-consequential load

August 30, 2010

34

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
will NOT lead to BES instability, voltage collapse, or cascading outages, which is what FERC
and NERC are charged with preventing. It will lead to the shedding of load in a local area
only. Utilities do not drop customers lightly. If the meter isn’t turning, we are not getting
paid, so we want the meter spinning. Utility power, while vital to our normal day-to-day
lives and infrastructure, was never intended to be without interruption.

Brad Chase

Orlando Utilities
Commission

1

Affirmative

This change raises the bar on transmission system performance. This change applies a
blanket requirement upon entities that does not take into account the number of outages,
probability of outages or cost to the customer. There are certain to be situations where this
blanket requirement will result in increased cost to customers for no noticeable increase in
reliability. OUC does agree with the concept of greater clarification on this requirement,
however this clarification may raise the bar to far by trying to establish a blanket
requirement. Duke, Progress Energy and others will be submitting comments with
proposed language that attempt to address some of these issues and we encourage the
drafting team to consider those comments.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of

August 30, 2010

35

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Eric Egge

Black Hills Corp

1

Negative

Black Hills believes that the prohibition of loss of non-consequential load for events
resulting in the loss of a single element inappropriately reaches beyond the reliability of the
bulk power system to local load quality of service issues. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. NERC should be
allowed to hold a public technical conference, as described in NERC’s April 19, 2010,
request for rehearing before being required to develop and submit clarifications to footnote
b of Table 1.

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Negative

PG&E commends the SDT for developing the proposed footnote b. While it is a great
improvement over the complete prohibition on loss of non-consequential load for any single
contingency, the planned and controlled interruption of a small amount of load, under
certain conditions, is not a risk to reliability or an indication of an unreliable system, but
rather, serves to preserve the reliability of the bulk power system. Transmission Planners
and Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system, especially where the impact is local in nature, to avoid
instability, cascading or uncontrolled separation. Such planned interruption of load may be
a reasonable alternative to the environmental impacts or prohibitive costs associated with a
major new transmission project. Given the potential impacts of the proposed modification,
further vetting of the issues is needed. PG&E believes that NERC should be allowed to hold
a public technical conference, as described in NERC’s April 19, 2010, request for rehearing
before being required to develop and submit clarifications to footnote b of Table 1.

August 30, 2010

36

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
RRI supports the WECC position on this issue; namely, that the prohibition of loss of nonconsequential load for events resulting in the loss of a single element inappropriately
reaches beyond the reliability of the bulk power system to local load quality of service
issues. The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project. NERC should be allowed to hold a public technical conference, as
described in NERC’s April 19, 2010, request for rehearing before being required to develop
and submit clarifications to footnote b of Table 1.

Thomas J.
Bradish

RRI Energy

5

Negative

Trent
Carlson

RRI Energy

6

Negative

John Tolo

Tucson Electric
Power Co.

1

Negative

The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project.

James
Tucker

Deseret Power

1

Negative

The prohibition of loss of non-consequential load for events resulting the loss of a single
element inappropriately reaches beyond the reliability of the bulk power system to local
load quality of service issues. The planned and controlled interruption of a small amount of
load, under certain conditions, is not a risk to reliability or an indication of an unreliable
system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including

August 30, 2010

37

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

Louise
McCarren

Western Electricity
Coordinating
Council

10

Negative

The proposed revisions to footnote b of Table 1 are an improvement to the recently
balloted prohibition on loss of non-consequential load for single contingencies. The
recognition of the new term "temporarily radial" is a step in the right direction. However,
the planned and controlled interruption of a small amount of load, under certain conditions,
is not a risk to reliability or an indication of an unreliable system, but rather, serves to
preserve the reliability of the bulk power system. Transmission Planners and Planning
Coordinators should be given the discretion to determine whether or not the planned and
controlled interruption of load is an appropriate system response to certain contingencies,
taking into consideration all factors, including customer and local regulator input, for their
individual system. Often times when planned load interruption is identified as a response to
a single event, the impact to the system is local in nature. The planned interruption of load
may be the alternative to prohibitive costs associated with a major new transmission
project. NERC should be allowed to hold a public technical conference, as described in
NERC’s April 19, 2010, request for rehearing before being required to develop and submit
clarifications to footnote b of Table 1.

William
Mitchell
Chamberlain

California Energy
Commission

9

Negative

While the proposed revisions to footnote b are an improvement to the prohibition on loss of
non-consequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, the prohibition of loss of non-consequential load for events resulting the loss of a
single element still inappropriately reaches beyond the reliability of the bulk power system
to local load quality of service issues. The planned and controlled interruption of a small
amount of load, under certain conditions, is not a risk to reliability or an indication of an
unreliable system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is

August 30, 2010

38

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

John Mick

Colorado Springs
Utilities

6

Negative

Colorado Springs Utilities ballot on the proposed changes to TPL Table 1, footnote b
directed in FERC Order RM06-16-009 Colorado Springs Utilities wishes to vote NO on the
proposed changes to TPL Table 1, footnote b, directed in FERC Order RM06-16-009. CSU
concurs with the WECC position paper for the ballot, and agrees with the WECC statement
“that the prohibition of loss of non-consequential load for events resulting in the loss of a
single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues”.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.
The SDT agreed that a technical conference on this issue would be of value and held such a conference on August 10, 2010.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and

August 30, 2010

39

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Horace
Stephen
Williamson

Southern Company
Services, Inc.

1

Negative

Richard J.
Mandes

Alabama Power
Company

3

Negative

Anthony L
Wilson

Georgia Power
Company

3

Negative

Gwen S
Frazier

Gulf Power
Company

3

Negative

Don Horsley

Mississippi Power

3

Negative

Michael
Ibold

Xcel Energy, Inc.

3

Negative

Liam
Noailles

Xcel Energy, Inc.

5

Negative

David F.
Lemmons

Xcel Energy, Inc.

6

Negative

August 30, 2010

Comments have already been submitted previously, but it will be added here again.
Proposed footnote should read... No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial
Transmission Facilities. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power transfers when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch. It must be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected. The proposed changes are based on the
following... “The proposed wording by the drafting team seems to imply that the
curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language
stated only that curtailments were permitted to prepare for the next contingency, not to
address loading related to the initial contingency. The proposed wording could be
interpreted to allow redispatch/firm curtailments to address any single contingency
constraint. Southern Companies recommend that the original language relating to
“preparing for the next contingency” be incorporated into the drafting team’s proposal.”
The proposed modification to footnote b of Table I in TPL-001 - 004 standards states that
after a Category B contingency, there should not be any thermal, voltage or stability
violation, no interruption of firm load (except the load that is directly connected to the
elements that are removed from service as a result of the contingency) and no firm
transfer curtailment (except when coupled with re-dispatch of resources obligated to redispatch). We believe the proposed footnote b creates a gap between TPL-002 and TPL003 standards, since it does not address conditions when firm load shedding and firm
transfer curtailments are not required to meet the system performance for Category B
contingency, but one or both are the required system adjustments to prepare for the next
contingency (Category C3). When firm transfer is curtailed after the first contingency in

40

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
preparation for the next contingency, it is not clear from the proposed footnote b if this is
considered a valid system adjustment for Category C or a violation of Category B. Recall
that the existing footnote b addresses this condition explicitly by stating “To prepare for the
next contingency, system adjustments are permitted, including curtailments of contracted
Firm Transfers.”

George T.
Ballew

Tennessee Valley
Authority

5

Affirmative

Marjorie S.
Parsons

Tennessee Valley
Authority

6

Affirmative

Larry Akens

Tennessee Valley
Authority

1

Affirmative

TVA appreciates the work of the SDT on this issue. However, TVA recommends revising the
second paragraph of the revised footnote b: “To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers. However, curtailment of Firm Transmission Service is
only allowed when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected.” Without the changes in the first two
sentences above, the proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to address any single contingency constraint instead of in
preparation for the next contingency.
TVA appreciates the work of the SDT. However, TVA recommends revising the second
paragraph of the revised footnote "b". Without changes in the first two sentences, the
proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to
address any single contingency constraint instead of in preparation for the next
contingency.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address
loading issues that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings,
not to bring the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities
may utilize ratings in the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT
does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd
paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Robert W.
Roddy

Dairyland Power
Coop.

1

Negative

DPC CONCURS WITH THE MRO COMMENTS.

Jason
Shaver

American
Transmission
Company, LLC

1

Affirmative

For Footnote b, add a third exception to the list, “or (3) end-use load that is either
accepted or volunteered by the customer". It is a widely-held understanding that the
tripping of non-consequential, end-use load is also allowed if the tripping of the load is
either accepted or volunteered by the customer.

Lawrence R.
Larson

Otter Tail Power
Company

1

Negative

The change precludes the use of direct load control systems that should be allowed to
relieve transmission problems. These systems control firm transmission load but rate
conditions can allow their use to mitigate transmission problems.

Response: (Note - MRO did not submit comments with the initial ballot – but did submit the following comment during the formal comment period: For
Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the customer". It is a widely-held
understanding that the tripping of non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered by the
customer in lieu of significant transmission system modifications. )

August 30, 2010

42

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

The SDT has modified the footnote to address your concern.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Ajay Garg

Michael D.
Penstone

Hydro One
Networks, Inc.

1

Hydro One
Networks, Inc.

3

August 30, 2010

Negative

Hydro One is casting a negative vote for the following reasons:
1. The amendment to the footnote does not add any technical value to the standard. It
was added only to satisfy a FERC directive to address comments made to allow nonconsequential load loss after a single contingency event, “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to
invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.”

Negative

2. Addressing curtailment of Firm Transmission Service with re-dispatch of resources is a
matter of a commercial nature and should be dealt with in the agreements dealing with
such services. Issues of contracted transmission services, firm or otherwise, are not a
reliability related matter and are not to be dealt with in this standard.

43

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
3. Matters of interruption of firm load should be incorporated into this standard only after
the FERC NOPR on the definition of the BES is resolved. As it stands, the footnote will pose
significant problems if the 100 kV and above FERC proposal is applied across the board,
unless the standard specifically states that it applies to the BES as defined by the region
(current definition).

Response: 1. & 2. The SDT disagrees. The SDT believes that there could be a direct impact on reliability of the BES associated with uncontrolled
interruption of Demand and that it is important to discourage and limit the use of this option.The SDT has added clarity to the footnote.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
3. The SDT disagrees that this needs to wait on the FERC NOPR. This standard is applicable to the BES as it is defined.
Spencer
Tacke

Modesto Irrigation
District

August 30, 2010

4

Negative

I am voting NO vote because of the lack of clarity of the second paragraph of the proposed
change. Although paragraph 1 is an improvement to the current wording, and actually
allows for some specific flexibility in shedding load for an N-1 event, the lack of clarity in
the second paragraph could lead to varied interpretations by members and compliance

44

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
auditors. Thank you.

Response: The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Dana
Cabbell

Southern California
Edison Co.

1

Negative

David
Schiada

Southern California
Edison Co.

3

Negative

August 30, 2010

It is SCE’s position that the planned and controlled interruption of a small amount of load,
under certain conditions, is not a risk to reliability or an indication of an unreliable system,
but rather, serves to preserve the reliability of the bulk power system. Transmission
Planners and Planning Coordinators should be given the discretion to determine whether or
not the planned and controlled interruption of load is an appropriate system response to
certain contingencies, taking into consideration all factors, including customer and local

45

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Ahmad
Sanati

Entity
South California
Edison Company

Segment

Vote

5

Negative

Comment
regulator input, for their individual system. When planned load interruption is identified as
a response to a single event, the impact to the system is often local in nature. The planned
interruption of load may be a desirable alternative to the prohibitive costs associated with a
major new transmission project.
If the NERC Standards Drafting Team decides to proceed with footnote B, as written, it
needs to ensure that Transmission Owners, Transmission Operators, and Transmission
Planners have enough time to both design and implement any mitigation plans necessary
to be compliant with the new language. In almost all cases the actual implementation of a
solution requiring new construction will be dependent on a number of different regulatory
agencies providing the necessary permits allowing for its construction. As such, NERC
needs to ensure that any time frame associated with compliance to the proposed language
be variable, and allow for extended implementation time frames based on system
conditions that may delay placing mitigation plans in service. An example of a reasonable
variable time frame to be compliant with the proposed language in footnote B would be to
start the clock 60 months from receiving the pertinent environmental permitting. In
California this could be the issuance of a Draft Environmental Impact Review pursuant to
the California Environmental Quality Act.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.
The SDT has added more latitude for the Transmission Planner with the modifications and believes that 60 months should be sufficient.

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the

August 30, 2010

46

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Henry ErnstJr

Duke Energy
Carolina

August 30, 2010

3

Negative

On the initial ballot of TPL-001-1 Duke Energy also voted “Negative”, primarily because
Duke believes that the requirement prohibiting loss of non-consequential load for P1, P2.1
and P3 events is an overreach by the standard into local load quality of service issues. We
also sought rehearing on the Commission’s March 18 Order Setting Deadline for
Compliance (Docket No. RM06-16), with respect to this and other issues. We believe that
FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of
a single contingency appears to extend beyond measures needed for “reliable operation” of
the bulk-power system to prevent “instability, uncontrolled separation or cascading
failures,” none of which occur when utilities implement a planned and orderly loss of nonconsequential load. Hence, the Commission’s directive to prohibit utilities from
incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that
are needed for “reliable operation” of the bulk-power system as defined under Section 215
of the Federal Power Act. Such directive constitutes an overreaching of the Commission’s
jurisdiction under Section 215 of the Federal Power Act into the jurisdiction of state
commissions which generally have responsibility for overseeing quality of service issues
applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version
of TPL-001-1, it still does not allow Transmission Planners to use appropriate discretion
regarding loss of non-consequential load. Transmission Planners, customers, and local
regulators should jointly control the decision making when BES reliability is not an issue.
Often, the events are extremely improbable and the consequences of these events are local
in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. With this “Negative” vote, Duke

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
offers the following ideas on alternatives for the SDT to consider that will allow for
appropriate discretion and facilitate proper planning while allowing non-consequential load
loss (NCLL). The standard should allow for dropping of limited amounts of nonconsequential load in situations where it would be reasonable for a bounded time period
and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations
where the near term impact of load projections or implementation of nearby
transmission/generation projects will alleviate the necessity of an upgrade to meet N-1
conditions. Also, reliability of service to end-use customer is impacted by the entire system
from source to load. Where allowance for NCLL would not greatly impact individual end-use
customers’ level of reliability the transmission planner should consider its use. Normally
transmission system outages are a minor contributor to overall customer outage frequency
and duration. Instances where allowance for NCLL can be used to avoid projects without
greatly impacting a customer’s outage frequency and duration should be acceptable. Use of
reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be considered by the SDT for
determination of acceptable use of NCLL.

Luther E.
Fair

Gainesville
Regional Utilities

1

Affirmative

Even though I am voting in the affirmative, I agree that most of the comments offered by
Duke and Norther Indiana in their earlier statements have merit and should be considered.
Also, I believe that the use of reliability metrics should be considered by the SDT for
determination of acceptable use of NCLL.

Mace Hunter

Lakeland Electric

3

Negative

Reliability should consider the entire system from source to load. Where allowance for
NCLL would not greatly impact individual end-use customer’s level of reliability the
transmission planner should consider its use. Normally transmission system outages are a
minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to delay projects without greatly impacting a customer’s
outage frequency and duration should be acceptable.
Use of reliability metrics should also be considered by the SDT for determination of
acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.

August 30, 2010

48

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Sammy
Roberts

Progress Energy
Carolinas

1

Negative

Lee
Schuster

Florida Power
Corporation

3

Negative

August 30, 2010

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect
to conditional allowance of curtailing Firm Transmission Service, which is addressed in the
second paragraph of the proposed new footnote (b). PE remains concerned, however, that
the first paragraph of the proposed new footnote (b) does not allow for curtailment of nonradial non-consequential load. The ability to curtail non-consequential load in the planning
horizon can be a useful tool to mitigate local area issues, and has not been detrimental to

49

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Sam Waters

Wayne
Lewis

Entity
Progress Energy
Carolinas

Progress Energy
Carolinas

Segment

Vote

3

Negative

5

Negative

Comment
the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly
at a localized self-contained level of the system, i.e. the distribution system(s) served by
the Transmission Owner. Prohibiting the curtailment of local load thus constitutes
regulating distribution feeder reliability rather than BES reliability. Events that could be
mitigated through the curtailment of local, non-radial non-consequential load are
infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the
proposed footnote (b) be considered: “No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, and/or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that Load must be interrupted to meet performance requirements only on those
now radial Transmission Facilities, and/or (3) Planned or controlled interruption of any
additional Load required to mitigate the post-contingency results, provided that the nonconsequential load being shed for the event is localized, and provided that the total load
shed for the event does not exceed 2% of the Planned system peak demand or 200 MW,
whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability. The SDT did not adopt a numerical limit as it believes that any single numerical value applied
on a ntion-wide basis was not equitable for all entities.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial

August 30, 2010

50

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Timothy
VanBlaricom

California ISO

2

Negative

The California ISO supports NERC’s request for a public technical conference to be held, as
described in NERC’s April 19, 2010 request for rehearing and motion for stay of the March
18 Order (RM06-16-009), to provide the opportunity to gain industry input and written
comments regarding the Commission’s TPL-002-0 directive for NERC to develop a
modification to the TPL-002-0 Table 1 footnote b.

Response: The SDT agreed that a technical conference would be of value and held such a conference on August 10, 2010.
Terry L.
Blackwell

Santee Cooper

1

Negative

Zack
Dusenbury

Santee Cooper

3

Negative

Suzanne
Ritter

Santee Cooper

6

Negative

August 30, 2010

The Commission’s directive to prohibit utilities from incorporating carefully controlled loss of
non-consequential load into their planning processes appears to extend the Commission’s
reach beyond its review of measures that are needed for “reliable operation” of the bulkpower system as defined under Section 215 of the Federal Power Act. Such directive
constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the
Federal Power Act into the jurisdiction of state commissions which generally have
responsibility for overseeing quality of service issues applicable to local load. Table B
footnote still does not allow Transmission Planners to use appropriate discretion regarding
loss of non-consequential load. Transmission Planners, and local customers should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. The Commission’s directive sets forth
an expectation that NERC is to implement standards that address all loss of load at costs
that may not be commensurate with bulk power system reliability, as statutorily defined,
which is fundamentally different from what the Reliability Standards were intended to do.

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Response: The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Kimberly J.
Jones

North Carolina
Utilities
Commission

9

Negative

The NC Utilities Commission is concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1, and as explained in draft footnote b,
is an inappropriate overreach into service issues that are more appropriately addressed by
state regulatory commissions. This requirement does not provide any benefit to reliability
of the bulk electric system and could undermine state efforts to balance reliability issues
with cost of service issues. The standard should continue to allow Transmission Planners to
use discretion regarding loss of non-consequential load, understanding that state
commissions are positioned to force electric utilities to address local service quality issues
on an expedited basis, should it be necessary and in the public interest.

Response: The SDT understands the concern but believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES. The SDT’s approach will leverage existing processes to document and vet the situation.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the

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Voter

Entity

Segment

Vote

Comment

Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
James L.
Jones

Southwest
Transmission
Cooperative, Inc.

1

Negative

THE PROPOSED INTERPRETATION WILL UNDERMINE THE INTERNATIONAL STANDARDS
SETTING PROCESS AND COULD RESULT IN DIFFERING INTERPRETATIONS OF
STANDARDS ON THE NORTH AMERICAN BULK-POWER SYSTEM.

Response: The SDT disagrees and believes that the footnote has been clarified appropriately within the standards development process.
Daryn
Barker

Louisville Gas and
Electric Co.

6

Negative

The revised footnote b on Table 1 imposes additional requirements on the responsible
entities. The footnote states: Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.
However, R1 states: The Planning Authority and Transmission Planner shall each
demonstrate through a valid assessment that its portion of the interconnected transmission
system is planned These statements address different and inconsistent scope. If the
change in scope was intended then a change should also be made to R1 to reconcile the
inconsistency.

Charlie
Martin

Louisville Gas and
Electric Co.

5

Negative

Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions should also be respected. However, R1 states: The
Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned These
statements address different and inconsistent scope. If the change in scope was intended
then a change should also be made to R1 to reconcile the inconsistency.

Response: The SDT agrees that your assessment is for your portion of the interconnected grid. However, when performance in one system is dependent
on generation dispatch in another system or vice versa, the SDT believes that one must ensure that the re-dispatch is feasible. The SDT does not believe
that this presents a conflict with Requirement R1.
John
Apperson

PacifiCorp

August 30, 2010

3

Negative

This proposal warrants a “no” vote due to the current uncertainty regarding the outcome of
the FERC TPL-002 NOPR issued by FERC on March 18, 2010. The impacts of the proposed
changes to footnote B cannot be assessed separately from the alternative interpretation of
TPL-002 proposed by FERC. The proper planning of a transmission system requires that all
performance requirements are known and understood. If only some of the requirements
are known and understood it is impossible to properly plan, study, assess, and operate the

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Entity

Segment

Vote

Comment
transmission system.

Response: The current TPL-002 is in force and will remain so until the completion of the cited FERC NOPR. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.
Keith V.
Carman

Tri-State G & T
Association Inc.

1

Negative

Tri-State does believe that the new footnote is an improvement, but thinks there are still
some changes necessary. We believe that the word “only” should be removed from the
phrase “...where that Load must be interrupted to meet performance requirements only on
those now radial Transmission Facilities” because that discrimination was not required in
FERC Order RM-06-16-009. There may be times when facilities near the temporary radial
facilities might fall outside the limits set in reliability criteria but the situation is mitigated if
the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State
recommends changing it to "Curtailment of Firm Transmission Service is not allowed unless
it is coupled with curtailment-offsetting resources that are obligated to re-dispatch. Further,
the curtailment activities cannot result in the shedding of any Firm load or in violations of
Facility Ratings, either internal or external to the planning region."
We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of nonconsequential load in the event of a single contingency appears to extend beyond
measures needed for “reliable operation” of the bulk-power system to prevent “instability,
uncontrolled separation or cascading failures,” none of which occur when utilities
implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of nonconsequential load into their planning protocols appears to extend the Commission’s reach
beyond its review of measures that are needed for “reliable operation” of the bulk-power
system as defined under Section 215 of the Federal Power Act. Such directive constitutes
an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for
overseeing quality of service issues applicable to local load.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.

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Voter

Entity

Segment

Vote

Comment

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
The SDT is not in position to comment on FERC’s authority.
Claudiu
Cadar

GDS Associates,
Inc.

1

Negative

We do not agree with the proposed changes due to several reasons. Although the
proposed change will directly influence the reliability standards and transmission system
performances, will also have an indirect impact on the economic side with respect to the
expansion of existing transmission system. We believe that FERC directive as stipulated in
Order 693 cannot constrict, nor impose certain actions outside of the reliability limits. We
believe that since these events are merely isolated and rarely enforced, the decision of
mandating a great financial effort as a consequence of the proposed changes would
certainly be counterbalanced by its feasibility when compare with the current cost of load
shedding. While the revised footnote b can be certainly considered an improvement from
the current version, however it still does not allow the joined entities involved to have
power over the decision making when BES reliability is not an issue.
We also believe that any mandatory changes implemented in the TPL standards under the

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Voter

Entity

Segment

Vote

Comment
current scenario are not entirely feasible unless all other issues such as the definition of the
BES, Consequential / Non-consequential Load, BES Critical Element, etc gets resolve ahead.
The revision with respect to load shedding, specifically the portion about shedding loads on
newly radial facilities, does not match the version 1 TPL standard definition of
consequential load loss. To approve the proposed revision to footnote ‘b’ would create an
unnecessary discrepancy between the version 1 TPL standard under consideration and the
existing standards. We recognize that the Version 1 will replace Version 0, but since it
appears that the performance standard with respect to footnote ‘b’ is intended to be same
in the revised footnote and the Version 1 standard, it only makes sense that the revised
version 0 footnote ‘b’ match the consequential load loss definition contemplated in Version
1.
In the light of the above we suggest the Commission to approach different other solutions
and ideas for improving the current reliability of the transmission system without enforcing
decisions beyond its statutory scope. We advance an alternative to this matter meant to
balance the reliability of the transmission system and its indirect financial impact. Although
the solution that we offer would require an extended time for development and
implementation, however we urge NERC to consider it in its further approach. Our
alternative consists mainly in implementing an additional term such as “Critical Load” which
we have briefly figured that would consist in particular load necessary to be maintained in
service without interruption. Even though this new term would seemed to be at first related
with the quality of the service, however a joint association of transmission planners,
customers, regulatory entities as decision makers can simply individualize the load that
cannot be shed, as well as future transmission improvements that will be required to serve
this envisioned small amount of load rather than the entire load. In this way we will create
a reasonable balance in between the reliability of the transmission system and the cost to
maintain / improve this reliability.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When

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Voter

Entity

Segment

Vote

Comment

interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
The current TPL-002 is in force and will remain so for the forseeable future. This limited scope revision to footnote ‘b’ is to add clarity to what is in effect.
Project 2006-02 is under revision and the clarifications of footnote ‘b’ will be considered by the SDT for future revisions of TPL-001-2.
The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the various
industry concerns while assuring BES reliability.
Ronald D.
Schellberg

Idaho Power
Company

1

Negative

While the proposed revisions are an improvement to the prohibition on loss of nonconsequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, that the prohibition of loss of non-consequential load for events resulting the loss of
a single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues.
However, the removal of: "To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers." will require significant adjustments in either TRM or TTC reductions to be
compliant with this revised standard in the WECC Region. To construct additional
transmission facilities to maintain present day business could easily exceed 10 Billion
dollars throughout the WECC region. For example, the Pacific AC Intertie currently has a
TTC of 4800 MW spread across 3 500 kV transmission lines. With the loss of one
Transmission line, the Pacific AC intertie drops to 3200 MW. Removal of this sentence

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Voter

Entity

Segment

Vote

Comment
would require TP either to drop the Firm TTC of the Intertie to 3200, or include a TRM
reservation of at least 1600 MW. The TPs would not be able to say that a loss of 1600 MW
of import capacity would not result in curtailments of firm load. Just about all multi
transmission line paths in the WECC Region would suffer. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. In the case of long
interties between subregions of WECC, these interties have never been planned to operate
in this manner. Idaho Power recommends that the sentence permiting system adjustments
be reinserted into Footnote B.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring
the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may
utilize ratings in the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity
is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT
does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd
paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the

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Voter

Entity

Segment

Vote

Comment

Contingency, or
o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Francis J.
Halpin

Bonneville Power
Administration

5

Affirmative

For consistency, regarding the firm transfer issue, the term "Firm Transmission Service"
should be replaced with "Firm Transfers" in order to be consistent with the fourth column
of the existing Table 1 "Transmission System Standards - Normal and Emergency
Conditions".

Response: The SDT agrees and has made the change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application

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Entity

Segment

Vote

Comment

is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Kim Warren

Independent
Electricity System
Operator

2

Affirmative

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES
and Firm Demand and on the understanding that the NERC standards apply only to the BES
as defined in the NERC Glossary as follows: “As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with
neighbouring systems, and associated equipment, generally operated at voltages of 100 kV
or higher. Radial transmission facilities serving only load with one transmission source are
generally not included in this definition.” To be clear, our interpretation of the present
definition of BES is that it defers to each Regional Reliability Organization to define the
elements of the power system that are considered BES and, therefore in the NPCC Region,
"BES as defined by NERC" = "BPS as defined by NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
Jacquie
Smith

ReliabilityFirst
Corporation

10

Affirmative

If this revision is an urgent action, then the implementation timeframe should be shorter.
In the clarification paragraph below, I do not understand the first sentence. Are there
commas missing? What is the requirement and what is the exception?
Also, I question the validity of using “should” in the second sentence. If it is a requirement,
then it needs to be stated as a requirement. If it is a suggestion, then it does not belong in
the standard.
No curtailment of Firm Transmission Service is allowed except when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated
that Facilities remain within applicable Facility Ratings and those adjustments do not result
in the shedding of any firm Load. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.

Response: This was originally classified as an ‘urgent action’ revision to meet the FERC due date which was June 30, 2010, not because NERC had
classified the modification as urgent for reliability. Note that FERC modified the due date to March 31, 2011 - this allows several more months of

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Voter

Entity

Segment

Vote

Comment

development time and the SAR was revised to indicate that the proposed modification to footnote ‘b’ is no longer an Urgent Action revision.
Commas have been added as appropriate and a re-wording was made which should make this clear.
‘Should’ has been replaced by ‘would’ to provide additional clarity.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
David H.
Boguslawski

Northeast Utilities

1

Affirmative

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can
be better defined as the proposed revision is subject to interpretation by the different
entities and regulatory agencies. Future conflicts can be minimized by further clarifying the
proposed revision.
Also, NU is concerned that this new modification does not specify the amount of
permissible load shed nor does it require the planning entity to minimize load shedding
under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.

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Voter

Entity

Segment

Vote

Comment

. Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Donald S.
Watkins

Bonneville Power
Administration

1

Affirmative

Rebecca
Berdahl

Bonneville Power
Administration

3

Affirmative

Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with
"Firm Transfers" to be consistent with the fourth column of the existing Table 1
Transmission System Standards - Normal and Emergency Conditions.

Response: The SDT agrees and has made this change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.

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Voter

Entity

Segment

Vote

Comment

Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Frank
Gaffney

Florida Municipal
Power Agency

4

Affirmative

David
Schumann

Florida Municipal
Power Agency

5

Affirmative

Please see FMPA comments submitted through the concurrent comment period for Project
2010-11

Response: Please see the response to FMPA comments above.
Carter B
Edge

SERC Reliability
Corporation

10

Affirmative

The footnote makes clearer when load can be dropped for planning purposes. By making
this footnote more specific, it supports reliability and helps stakeholders apply the TPL
standards.

Response: Thank you for your support.

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Timothy
Beyrle

Entity

Segment

Vote

Comment

4

Affirmative

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all
honesty, shedding load for local area impacts has nothing to do with BES reliability and
should not be under FERC jurisdiction under Section 215 of the Federal Power Act, but
rather State jurisdiction for quality of service issues. However, there is also the matter of
FERC jurisdiction over commercial matters and the opportunity to “game” the original
footnote by transmission providers by allowing firm load shedding to grant firm
transmission service for themselves, thereby avoiding or deferring transmission investment,
while at the same time denying or requiring others to build the same transmission avoided
in order to obtain transmission service. We can see how difficult it is from a drafting team’s
perspective in achieving a balanced position between these different matters. The drafting
team should be applauded for finding a reasonable position.

1

Affirmative

This issue is better handled within the development of the new TPL-001 standard.

City of New
Smyrna Beach
Utilities
Commission

Response: Thank you for your support.
Larry E Watt

Lakeland Electric

Response: The current TPL-002 is in force and will remain so until the completion of the TPL-001-2 effort. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.

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Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project
20010-11
The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on
the revised footnote. These standards were posted for a 30-day informal public comment
period from September 8, 2010 through October 8, 2010. The stakeholders were asked to
provide feedback on the standards through a special Electronic Comment Form. There were
42 sets of comments, including comments from more than 96 different people from
approximately 75 companies representing 7 of the 10 Industry Segments as shown in the
table on the following pages.
Comments can be reviewed in their original format on the following project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html

Industry response was divided in relation to support for the proposed footnote ‘b’
which was posted for an informal comment period through October 8, 2010.
Although there were a number of supporters for the proposed footnote they were
outnumbered by the commenters who did not support the footnote text for various
reasons and offered their views and concerns.
The Standard Drafting Team (SDT) carefully considered the feedback provided
including minority opinions such as not allowing Demand interruption at all and has
made clarifying revisions to the footnote ‘b’ text.
The revised footnote ‘b’ is:
b) An objective of the planning process is to avoid should be to minimize the
likelihood and magnitude of interruption of Demand following Contingency
events. Interruption of Demand is discouraged and measures to mitigate such
interruption should be pursued within the planning process. However, it is
recognized that Demand may need to will be interrupted if it is directly served
by the elements removed from service as a result of the Contingency.
Furthermore, in limited circumstances Demand may need to be interrupted to
address BES performance requirements. When interruption of Demand is
utilized within the planning process to address BES performance requirements,
such interruption is limited to:
•
•
•

Demand that is directly served by the elements that are removed from
service as a result of the Contingency
Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability where the
cCircumstances describing where the use of such Demand interruption are
documented, including alternatives evaluated; and where the application
Demand interruption is subject to review and acceptance in an open and
transparent stakeholder process that includes addressing stakeholder
comments.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Based on the review of comments received and the fact that only clarifying changes were
made due to those comments, the SDT is recommending that this project be moved forward
to balloting.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Index to Questions, Comments, and Responses
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC
Orders which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding
the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system. Do you agree with the proposed changes and if not,
please provide specific reasons for your disagreement.…. ......................................... 9

October 27, 2010

3

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

Additional Member

Northeast Power Coordinating Council
Additional Organization

New York State Reliability Council, LLC

NPCC 10

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Micahel Schiavone

National Grid

NPCC 1

4. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5. Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7. Dean Ellis

Dynegy Generation

NPCC 5

4

5

6

7

8

9

10

NPCC 8

9. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

10. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC 5

11. Kathleen Goodman

ISO - New England

NPCC 2

12. Chantel Haswell

FPL Group, Inc.

NPCC 5

13. David Kiguel

Hydro One Networks Inc.

NPCC 1

14. Michael R. Lombardi

Northeast Utilities

NPCC 1

October 27, 2010

3

Region Segment Selection

1. Alan Adamson

8. Brian Evans-Mongeon Utility Services

2

4

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

15. Randy MacDonald

New Brunswick System Operator

NPCC 2

16. Bruce Metruck

New York Power Authority

NPCC 6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

18. Robert Pellegrini

The United Illuminating Company

NPCC 1

19. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

20. Saurabh Saksena

National Grid

NPCC 1

Philip R. Kleckley

SERC Planning Standards Subcommittee

2.

Group

Additional
Member

Additional
Organization

Region

Bob Jones

Southern Company Services - Trans

SERC

1

John Sullivan

Ameren

SERC

1

3.

Charles Long

Entergy

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative

SERC

1

5.

Pat Huntley

SERC Reliability Corporation

Carol Gerou

Additional Member

6

7

8

9

10

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

WPS Corporation

MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Murdock

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

October 27, 2010

5

10

MRO's NERC Standards Review
Subcommittee

Additional Organization

4

Segment Selection

2.

Group

3

1, 3, 5

1.

3.

2

5

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12. Scott Nickels

Rochester Public Utilties

MRO

4

MRO

1, 3, 5, 6

13. Terry Harbour

4.

Group

MidAmerican Energy Company

Denise Koehn

Additional Member

Bonneville Power Administration

Additional Organization
BPA, Transmission Planning

WECC 1

2. Berhanu Tesema

BPA, Transmission Planning

WECC 1

3. Kyle Kohne

BPA, Transmission Planning

WECC 1

4. Kendall Rydell

BPA, Transmission Planning

WECC 1

5. Rebecca Berdahl

BPA, Long Term Sales and Purchases WECC 3

Group

Louis Slade, Jr.

3

4

5

6

7

8

9

1, 3, 5, 6

Region Segment Selection

1. Chuck Matthews

5.

2

Dominion

1, 3, 5, 6

Additional Member Additional Organization Region Segment Selection
1. Angela Park

Electric Transmission

SERC

1, 3

2. John Loftis

Electric Transmission

SERC

1, 3

3. Mike Garton

Electric Market Policy

NPCC 5, 6

4. Michael Gildea

Electric Market Policy

RFC

6.

Ben Li

Group

5, 6

IRC Standards Review Committee

2

Additional Member Additional Organization Region Segment Selection
1. Bill Phillips

MISO

MRO

2

2. Partick Brown

PJM

RFC

2

3. James Castle

NYISO

NPCC 2

4. Mark Thompson

AESO

WECC 2

5. Charles Yeung

SPP

SPP

6. Greg Van Pelt

CAISO

WECC 2

7. Matt Goldberg

ISO-NE

NPCC 2

October 27, 2010

2

6

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7.

Individual

Jana Van Ness

Arizona Public Service Company

X

X

X

8.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

9.

Individual

John Cummings

PPL Corp

X

X

X

10.

Individual

Andy Tillery

Southern Company

X

X

11.

Individual

Don Gilbert

JEA

X

X

X

12.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

X

X

X

X

13.

Individual

Laura Zotter

ERCOT ISO

14.

Individual

Greg Rowland

Duke Energy

X

X

X

X

15.

Individual

Steve Stafford

Georgia Transmission Corporation

X

16.

Individual

John Canavan

NorthWestern Energy

X

17.

Individual

Tim Ponseti

TVA Transmission Planning & Compliance

X

X

X

18.

Individual

Gordon Rawlings

BC Hydro

X

X

X

19.

Individual

Jon Kapitz

Xcel Energy

X

X

X

X

20.

Individual

John Sullivan

Ameren

X

X

X

X

21.

Individual

Darcy O'Connell

California ISO

22.

Individual

Doug Hohlbaugh

FirstEnergy

X

X

October 27, 2010

7

8

9

X

X

X

X

X
X

X

X

7

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

23.

Individual

Orlando A Ciniglio

Idaho Power

X

X

X

24.

Individual

Michael Lombardi

Northeast Utilities

X

X

X

25.

Individual

Thad Ness

American Electric Power

X

X

X

X

26.

Individual

JC Culberson

ERCOT

27.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

28.

Individual

Charles Lawrence

American Transmission Company

X

29.

Individual

Kathleen Goodman

ISO New England Inc.

X

30.

Individual

Dan Rochester

Independent Electricity System Operator

X

31.

Individual

Ed Davis

Entergy Services

X

X

X

X

32.

Individual

Terry Harbour

MidAmerican Energy

X

X

X

X

33.

Individual

Patrick Farrell

Southern California Edison Company

X

X

X

X

34.

Individual

Jonathan Appelbaum

United Illuminating Co

X

35.

Individual

Michael Moltane

ITC

X

36.

Individual

Gregory Campoli

New York Independent System Operator

37.

Individual

David Kiguel

Hydro One Networks Inc.

38.

Individual

Jason Marshall

Midwest ISO

October 27, 2010

7

8

9

X

X
X

X
X

8

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

39.

Individual

Claudiu Cadar

GDS Associates Inc.

X

40.

Individual

Chifong Thomas

Pacific Gas and Electric Co.

X

41.

Individual

Catherine Koch

Puget Sound Energy

X

42.

Individual

Harold Wyble

Kansas City Power & Light

X

October 27, 2010

2

3

4

5

X

X

X

X

6

7

8

9

X

9

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Orders which required the
ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system. Do you agree with the proposed changes
and if not, please provide specific reasons for your disagreement.
Summary Consideration: Industry response was divided in relation to support for the proposed footnote ‘b’ which

was posted for an informal comment period through October 8, 2010. Although there were a number of supporters
for the proposed footnote they were outnumbered by the commenters who did not support the footnote text and
offered their views and concerns.
The Standard Drafting Team (SDT) carefully considered the feedback provided and has made clarifying revisions to
the footnote ‘b’ text. For each major item, the SDT has addressed the issue raised and has summarized any
revision made to footnote ‘b’ in response to the feedback provided. The SDT appreciates industry input and believes
the changes made are responsive to the comments received.
Open and Transparent Process: Most of the comments received related to the use of an “open and transparent”
stakeholder process as described in the proposed footnote ‘b’. While the comments on this topic varied, the
majority of comments indicated that such a process should not be included within a mandatory Reliability Standard
and cited that FERC Order 890 already requires the sharing of planning information. Others indicated that the
statement for “review and acceptance” exceeds expectations required by FERC Order 890 and that an entity’s
compliance to a Reliability Standard should not be subject to the “acceptance” of stakeholders and that a process
conforming with FERC Order 890 principles already requires dispute resolution. Some commenters expressed
support of the process and it is noted that those who responded “Yes” with no comment were assumed to support
the process “as is”.
The SDT’s inclusion of a stakeholder review in footnote ‘b’ was driven by the fact that FERC Order 890 does not fully
cover the continent-wide footprint addressed by a NERC Reliability Standard. Additionally, footnote ‘b’ is being
applied to address localized Bulk Electric System performance and not a wide-area Bulk Electric System concern
that is generally the focus of the “open and transparent” process governed by FERC Order 890.
The SDT thoroughly considered all comments on the stakeholder process model. The SDT continues to support a
Reliability Standard providing mandatory enforcement utilizing a stakeholder process where any intended use of
planned Demand interruption has transparency and that stakeholders have the opportunity to comment on its use.
However, upon further reflection the majority of SDT members agreed that including the “acceptance” aspect of the

October 27, 2010

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

stakeholder process presents challenges within the context of a Reliability Standard and “acceptance” has been
removed. The SDT agrees with opinions that an entity’s compliance should not be subject to the “acceptance” of its
plans by stakeholders. Also, the SDT realizes that for most entities there is a final, high level review with
acceptance or approval of Transmission plans at the local level. So, while the footnote no longer references the
need for stakeholder acceptance, the expectation is that there will be a review process in place that will consider the
implementation of any plan calling for Demand interruption as explained in the footnote.
In addition, the SDT has revised footnote ‘b’ to explicitly require a response to any challenges presented via the
stakeholder process.
Demand vs. Load: Several commenters questioned the SDT’s use of the term “Demand” instead of “Load” in the
proposed footnote. The SDT clarifies that this was intentional as the existing, approved TPL suite of standards uses
the term Demand throughout the requirement text. Additionally, the existing, approved TPL performance
requirements documented in Table I contain the column heading “Loss of Demand or Curtailed Firm Transfers”
which is the subject of the footnote ‘b’ applicability for category B (single element) Contingencies. This project,
Project 2010-11, aims to address footnote ‘b’ regulatory directives with no change to the remainder of the standard.
Therefore, for consistency with the existing standard text, the term Demand is retained.
Firm transfer vs. Firm Transmission Service: Some stakeholders suggested that the SDT revert back to the
use of “Firm Transmission Service” instead of the undefined term “firm transfers.” The SDT clarifies that that the
change to “firm transfers” was intentional as the existing, approved TPL suite of standards references “firm
transfers” both in requirement text and Table I. The existing, approved TPL performance requirements documented
in Table I contain the column heading “Loss of Demand or Curtailed Firm Transfers” which is the subject of the
footnote ‘b’ applicability for category B (single element) Contingencies. This project, Project 2010-11, aims to
address footnote ‘b’ regulatory directives with no change to the remainder of the standard. Therefore for
consistency with the existing standard text, the term ‘firm transfer’ is retained.
Amount of Demand Loss: The majority of commenters agree with the SDT’s clarifications regarding interruption
of Demand as defined in the proposed footnote ‘b’. The majority of entities who commented support the limited use
of Demand interruption and that when used to address a BES performance requirement agree that it should be
documented, and made known through a stakeholder process. However, as stated above, the majority stopped
short of supporting a mandatory Reliability Standard requiring “acceptance” by other entities for the planned
interruption of Demand.

October 27, 2010

11

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Other minority views propose to limit or cap the amount of Demand loss and some suggested 50 MW as the
appropriate level. Some felt the SDT’s prior approach of limiting the Demand loss to only “radial” line configurations
was appropriate and superior to the “open process” approach. It is also noted that some commenters went further
to say no loss of Demand should be allowed for a single Contingency, but this was clearly a minority view of the
comments submitted.
The SDT carefully considered the comments and unanimously agreed that defining a Demand level limit is
problematic based on the vast differences in BES applications across the continent and that each potential use is
case specific. The SDT also had concerns that setting such a limit may have the unintended consequences of
planned Demand interruption being more widely accepted in practice in Transmission planning. The SDT and most
commenters are of the opinion that a stakeholder review process is a better deterrent for Demand interruption and
will appropriately guard against any misuse.
The revised footnote ‘b’ is:
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of
interruption of Demand following Contingency events. Interruption of Demand is discouraged and measures to
mitigate such interruption should be pursued within the planning process. However, it is recognized that
Demand may need to will be interrupted if it is directly served by the elements removed from service as a result
of the Contingency. Furthermore, in limited circumstances Demand may need to be interrupted to address BES
performance requirements. When interruption of Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to:
•
•
•

Demand that is directly served by the elements that are removed from service as a result of the Contingency
Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability where the cCircumstances describing where the
use of such Demand interruption are documented, including alternatives evaluated; and where the application
Demand interruption is subject to review and acceptance in an open and transparent stakeholder process that
includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.

October 27, 2010

12

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization
Northeast Power Coordinating
Council

Yes or No

Question 1 Comment

No

1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. Recommend that the drafting
team revise the wording to eliminate this implication, and soften the expectation such that it is recognized that
some Interruption of Demand is unavoidable by system configuration, but that each entity should establish a
reasonable limit on how much demand can be interrupted due to the loss of an element.
2. The Statement that “However, Demand may need to be interrupted in limited circumstances to address
BES performance requirements” in the introductory paragraph contradicts bullet 3 “Demand that does not
adversely affect BES ...”
3. The third Bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system,
documentation expectations, and to answer fundamental questions such as who has the authority to decide
the use if the stakeholder process is “accepting”, and the necessity of having a stakeholder process. It is
unlikely that the interruption of Demand will adversely impact the BES system. This constraint is too broad.
The language in this bullet also allows that non-consequential Demand interruption could be used to mitigate
reliability violations arising from the NERC Category B contingency events (i.e., single element
contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified.
5. In the last sentence of the second paragraph, “would” should be replaced by “must”.
Alternatively, possible rewording of footnote “b” to be considered: b) An objective of the planning process
should be to minimize the likelihood of interrupting Demand and measures to mitigate such interruption
should be pursued within the planning process. However, Demand may need to be interrupted in limited
circumstances to address BES performance requirements or other local reasons which have no adverse
impact on overall BES reliability or the interconnected BES. When interruption of Demand is utilized within
the planning process, such interruption is limited to: o Demand that is directly served by the elements that are
removed from service as a result of the Contingency o Demand that does not adversely impact overall
reliability of the BES or the interconnected BES and where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to
review and acceptance in an open and transparent stakeholder process. Curtailment of firm transfers is
allowed, when coupled with the appropriate re-dispatch of available resources, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of
any firm Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions would also be respected.
The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC

October 27, 2010

13

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
Glossary dated April 20, 2010) Demand is:”1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table.

Hydro One Networks Inc.

No

1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. Recommend that the drafting
team revise the wording to eliminate this implication, and soften the expectation such that it is recognized that
some Interruption of Demand is unavoidable by system configuration, but that each entity should establish a
reasonable limit on how much demand can be interrupted due to the loss of an element.
2. The Statement that “However, Demand may need to be interrupted in limited circumstances to address
BES performance requirements” in the introductory paragraph contradicts bullet 3 “Demand that does not
adversely affect BES ...”
3. The third Bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system,
documentation expectations, and to answer fundamental questions such as who has the authority to decide
the use if the stakeholder process is “accepting”, and the necessity of having a stakeholder process. It is
unlikely that the interruption of Demand will adversely impact the BES system. This constraint is too broad.
The language in this bullet also allows that non-consequential Demand interruption could be used to mitigate
reliability violations arising from the NERC Category B contingency events (i.e., single element
contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified.
5. In the last sentence of the second paragraph, “would” should be replaced by “must”. Alternatively, possible
rewording of footnote “b” to be considered: b) An objective of the planning process should be to minimize the
likelihood of interrupting Demand and measures to mitigate such interruption should be pursued within the
planning process. However, Demand may need to be interrupted in limited circumstances to address BES
performance requirements or other local reasons which have no adverse impact on overall BES reliability or
the interconnected BES. When interruption of Demand is utilized within the planning process, such
interruption is limited to: o Demand that is directly served by the elements that are removed from service as a
result of the Contingency o Demand that does not adversely impact overall reliability of the BES or the
interconnected BES and where the circumstances describing the use of such Demand interruption are
documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process. Curtailment of firm transfers is allowed, when coupled with
the appropriate re-dispatch of available resources, where it can be demonstrated that Facilities remain within

October 27, 2010

14

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions would also be respected.
The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC
Glossary dated April 20, 2010) Demand is:”1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table.

SERC Planning Standards
Subcommittee

No

The revised text relating to the planning process exceeds what is appropriate for a reliability standard.
Existing open and transparent stakeholder processes focus on larger system issues and not on local load
serving. We suggest the following: Demand may need to be interrupted in limited circumstances to address
BES performance requirements. When interruption of Demand is utilized within the planning process, such
interruption is limited to: o Demand that is directly served by the elements that are removed from service as a
result of the Contingency o Interruptible Demand or Demand-Side Management o Demand that does not
adversely impact overall BES reliability and is made temporarily radial as a result of the Contingency, where
that Demand must be interrupted to meet performance requirements. Curtailment of firm transfers is allowed
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in
the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions would also be respected. “
The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.”

Ameren

No

October 27, 2010

The revised text to footnote b relating to the planning process exceeds what is appropriate for a reliability
standard. Existing open and transparent stakeholder processes focus on larger system issues rather than on
local load serving issues. We suggest the following text for footnote b:Demand may need to be interrupted in
limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to: o Demand that is directly served by the elements
that are removed from service as a result of the Contingency o Interruptible Demand or Demand-Side
Management o Demand that does not adversely impact overall BES reliability and is made temporarily radial
as a result of the Contingency, where that Demand must be interrupted to meet performance requirements.
Curtailment of firm transfers is allowed when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the

15

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.

MRO's NERC Standards Review
Subcommittee

No

The revised draft is a significant improvement over the first draft. However, we suggest the following minor
changes:
1. The criterion of “adversely affect overall BES reliability” is undefined and maybe subject to a wide range of
interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words
“as defined by each Transmission Planner or Planning Authority”.
2. The term of “firm transfers” is undefined and maybe subject to a wide range of interpretation by
Transmission Planners, Planning Authorities, and auditors. So, we suggest establishing a definition for the
term, reverting to the “Firm Transmission Service” term, or using another appropriate defined term.

American Transmission
Company

No

The revised draft is a significant improvement over the first draft. However, we suggest the following minor
changes:
1. The criterion of “adversely affect overall BES reliability” is undefined and may subject to a wide range of
interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words
“as defined by each Transmission Planner or Planning Authority”.
2. The term of “firm transfers” is undefined and may subject to a wide range of interpretation by Transmission
Planners, Planning Authorities, and auditors. So, we suggest establishing a definition for the term of "firm
transfers", reverting to the “Firm Transmission Service” term, or using another appropriate NERC defined
term.

PacifiCorp

October 27, 2010

No

PacifiCorp believes that the current version of footnote “b” is an improvement over the language that currently
exists in the standard, except for one component of the revised footnote. The third bullet in the draft standard
currently limits the interruption of Demand if it does not adversely impact overall BES reliability, where the
circumstances describing the use of the interruption are documented (including alternatives evaluated) and
the application is subject to review and acceptance in “an open and transparent stakeholder process.”
PacifiCorp believes that the language requiring review and acceptance of an application of demand
interruption through any sort of stakeholder process should be removed. It is not practical or effective to
prescribe that either this standard or any other standard requires stakeholder approval in order to maintain
compliance. As presently drafted, this requirement for stakeholder review and acceptance appears to be
inconclusive and indeterminate as to what is required for registered entities to comply. Instead, this third
bullet should require the documentation, by the Planning Authority and Transmission Planner, of the
circumstances describing the use of Demand interruption - including methodologies used, assumptions relied
upon, and alternatives evaluated - as part of the Planning Authorities’ and/or Transmission Planners’

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Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
documentation of results in their annual Reliability Assessments. These annual assessments are already
submitted to the appropriate Regional Reliability Organization pursuant to TPL-002-1b Requirement R3. This
annual assessment can be provided by the ERO to other appropriate third parties upon their request.

Southern Company

No

The revised text relating to the planning process exceeds what is appropriate for a reliability standard.
Existing open and transparent stakeholder processes focus on larger system issues and not on local load
serving. We suggest that the drafting team go back to the concept of local load being the load that is made
temporarily radial by the contingency. That was a much better approach.

JEA

No

The requirement in general is acceptable; however, there needs to be an added "such as" clause to the
referenced "...in an open and transparent stakeholder processes." I suggest adding "..."...in an open and
transparent stakeholder processes such as the FERC approved regional 890 process that includes the load
serving entity affected".

South Carolina Electric and Gas

No

SCE&G believes the first sentence "An object of the planning process is to avoid interruption of Demand."
goes beyond what is appropriate for a reliability standard and therefore should be deleted. Also, the part of
the sentence that states "and where the application is subject to review and acceptance in an open and
transparent stakeholder process" goes beyond what is appropriate for a reliability standard and should be
deleted.

NorthWestern Energy

No

In addition to the three bullet items, add a fourth bullet item to the list of limitations under the body of footnote
b: “In no case will a total loss of load that is less than 50 MW be considered a violation of this standard.”

TVA Transmission Planning &
Compliance

No

TVA supports FERC's actions on improving reliability of the BES; however, TVA believes that the new
proposal is focusing more on reliability of local loads than on the overall reliability of the BES. Footnote b
should focus only on the overall reliability of the BES. Reliability of local loads should be addressed outside
the TPL standards and therefore should not be used/referenced in footnote b. Also existing stakeholder
processes (referred to in the SDT proposal) typically focus on larger system issues and not on local load
serving. Thus TVA believes that some local load should be allowed to be dropped in order to maintain BES
reliability. However TVA does believe that there should be a limit of how much load can be dropped in order
to maintain BES reliability. TVA believes that 50 MW is a reasonable number for this limit. Based on the
above, TVA proposes substituting the following for the revised footnote b:Demand may need to be interrupted
in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to: Demand that is directly served by the elements that
are removed from service as a result of the Contingency Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability, where that Demand (not to exceed 50 MW)

October 27, 2010

17

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
must be interrupted to meet performance requirements. Curtailment of firm transfers is allowed when coupled
with the appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any
firm Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions would also be respected.

BC Hydro

No

The SDT is to be commended for their efforts to develop clear, unambiguous language for Footnote “b”.
From the discussions that have taken place it seems that there are many different perspectives and to get
agreement on specific language will be very difficult. We believe that it would be useful to identify the main
issues that Footnote “b” needs to address and we consider those main issues to be:
o Definitions of (a) Consequential Load Loss, (b) Firm Demand, (c) Firm Transmission Capability (as distinct
from the OATT term, “Firm Transmission Service”), (d) Firm Transfer (this could be defined as transfers using
the OATT’s Firm Transmission Service, (e) Manual System Adjustments (capitalized in the Category C
section of TPL-001, but not defined in the NERC Glossary) and (f) the Bulk Electric System (BES).
o Identifying permissible Demand/Transfer curtailment actions for (a) the planning studies simulating the
Category B event itself and (b) the planning studies associated with determining acceptable actions for
preparing for the next set of contingencies should the initial single contingency be prolonged (ie, last several
weeks). This would define the acceptable (pre-emptive) “Manual System Adjustments” of Category C events.
o Define separate acceptable curtailment actions for (a) curtailment of Demand (ie, end-user load) and (b)
curtailment of market to market transfers, that very rarely, if ever, result in the loss of any end-user load.
o Define the planning studies required to determine the acceptability of the impacts on the BES resulting from
curtailments in a “remote” part of the system that have been accepted by those directly affected by those
curtailments.
At this point we don’t have specific language to suggest, but we do have the following comments that we
hope will help:
A. Interruption of Demand:
A.1. Consider improving the definition of “Firm Demand” in the NERC Glossary that now reads, “That portion
of the Demand that a power supplier is obligated to provide except when system reliability is threatened or
during emergency conditions”. Perhaps it could be changed to something like, “That portion of the Demand
that the planned transmission system must be able to supply without interruption for Category B events.
A.2. Consider stating in Footnote “b” that curtailment of Firm Demand is (a) not permitted in the simulation of
the N-1 event itself and (b) it is not permitted as part of the (pre-emptive) “Manual System Adjustments”
needed to prepare for the next set of contingencies should the initial single contingency be prolonged (ie, last

October 27, 2010

18

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
several weeks).
B. Interruption of Firm Transfers:
B.1. “Firm Transfers” could be defined as transfers using the OATT’s Firm Transmission Service, but consider
developing a system reliability-based term for “Firm Transmission Capability” instead of referring to the tariffbased NERC definition of “Firm Transmission Service”. This would recognize the difference between
planning standards and commercial/tariff rules. The NERC definition of “Firm Transmission Service” is now,
“The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no
planned interruption”. Transmission tariffs address the priority of curtailments when the loading on a
transmission path needs to be reduced for whatever reason (single- or multiple-contingencies). The NERC
transmission planning standards need a system reliability definition like, “Firm Transmission Capability” is the
transmission capability across a cut-plane, on a defined transmission path or across a defined flowgate that is
available, before any manual corrective actions are taken, following the worst Category B event under the
most onerous normal system conditions considering all plausible generation dispatch patterns and the full
range of expected load levels.”
B.2. Consider stating in Footnote “b” that curtailment of Firm Transfers is only permitted to the extent that
redispatch of generation can be implemented so that delivery to the Firm Transfer recipient is not interrupted
(a) in the planning studies of the Category B event itself and (b) as part of the (pre-emptive) “Manual System
Adjustments” needed to prepare for the next set of contingencies should the initial single contingency be
prolonged (ie, last several weeks).
C. General Comments:
C.1. Consider replacing the first bullet of the proposed Footnote “b” with simply “Consequential Load Loss”
since the NERC Project 2006 02 (TPL 001) Standard Drafting Team is introducing the following definition:
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result of
Transmission Facilities being removed from service by a Protection System operation designed to isolate the
fault
C.2. Consider removing “Demand-Side Management” (DSM) from the second bullet because that term is too
general. The present definition of DSM in the NERC Glossary is:”The term for all activities or programs
undertaken by Load-Serving Entity or its customers to influence the amount or timing of electricity they use”.
C.3. Consider being more specific on what constitutes acceptable “Interruptible Demand”, like: “Interruptible
Demand that is part of an automatic real-time Direct Control Load Management (DCLM) system that is
activated by the contingencies that require it and that is a completely “dual-redundant” scheme including all
communications equipment. The DCLM system must result in automatic curtailment of Demand that is fast
enough to maintain all BES system performance standards (eg, voltage stability, voltage dip, etc)”.

October 27, 2010

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Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
C.4. Consider eliminating the description of how interrupting Demand that does not adversely impact overall
BES reliability was accepted (ie, the stakeholder process, etc). If such a process were undertaken and it
resulted in acceptance that the Demand could be curtailed for Category B events, wouldn’t that simply mean
that the Demand was “Interruptible Demand”. It really doesn’t matter what process resulted in it being
accepted. The key considerations are that (a) if the interruption of that Demand is necessary to maintain BES
reliability, then it must be interrupted in a very reliable manner (ie, dual redundant scheme, etc) and (b) if the
interruption of that Demand is not necessary to maintain the reliable performance of the BES, then that should
be confirmed by the planning studies (ie, it doesn’t need to have an expensive, sophisticated, dual-redundant
DCLM scheme since the impact on the BES is acceptable even if the scheme doesn’t work).
D. Additional Questions related to Curtailment of Firm Transfers: In the past, the latter part of Footnote B
read: “To prepare for the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.”The last part of the proposed Footnote B
now reads: “Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable
Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities
external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions
would also be respected.”We would like to understand the implications of the proposed Footnote B as it
relates to curtailment of Firm Transfers (as per definition proposed earlier) for the following questions:
1) In the most recent draft of Footnote B, why was the NERC defined term ‘Firm Transmission Service’
replaced with the non-defined term ‘firm transfers’?
2) In the most recent draft of Footnote B, why was the tone softened from “No curtailment of Firm
Transmission Service is allowed, except...” to “Curtailment of firm transfers is allowed when...”?
3) Assuming an outage of a single transmission line (N-1 Category B event) has occurred and assuming that
no “resources [are] obligated to redispatch” for this outage, would a transmission provider be allowed to curtail
Firm Transmission Service (NERC defined term) that it has sold in order to prepare to withstand the next
worst credible contingency?
4) Would transmission providers be allowed to sell Firm Transmission Service on a path above what could be
delivered with any one element of that path out of service and a range of operating conditions?
5) If the proposed Footnote B is approved, would utilities have to reinforce their system (within 60 months) to
ensure that Firm Transmission Service for particular paths would not be curtailed can be delivered when any
one element of that path is out of service?
6) If a transmission provider employs Generation Dropping for single contingencies in order to support Firm
Transmission Service between regions, and assuming there are no provisions for obligated re-dispatch, would

October 27, 2010

20

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
the proposed Footnote B force a recalculation of firm vs non-firm transfer capability?
7) Path 66 (PACI) and Path 65 (PDCI) can both see significant derates in their firm transfer capability for
single contingencies. How would the proposed Footnote B impact Firm Transmission on these paths?

FirstEnergy

No

FirstEnergy appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable
proposal for clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also
commend NERC staff for convening an industry technical conference to discuss the topic and FERC staff for
their participation in the technical conference as the industry carefully considered various perspectives. The
proposed footnote B is much improved from the prior draft proposals.
One change that FirstEnergy proposes is to strike the text following the semicolon in the third bullet item
which states “and where the application is subject to review and acceptance in an open and transparent
stakeholder process.” This text may be intended as explanatory but has the appearance of mandating an
approval process that will be auditable through the TPL reliability standards. The statement is not needed
within the framework of mandatory reliability requirements as FERC Order 890 already mandates an open
and transparent process related to the planning of the bulk electric system. FERC via the 890 Final Rule
modified the pro forma Open-Access Transmission Tariff to require open and transparent stakeholder process
to better ensure no undue discrimination and access to the transmission system. The Final Rule beginning at
paragraph 418 discusses reform to the Coordinated, Open and Transparent Planning of the transmission
system. The Commission direction included eight planning principles required to be within the open process one of which is dispute resolution. It should be well understood that the transmission planner and planning
coordinator share and disseminate all of their planning study results and proposed corrective actions including the proposed use of Demand interruption - as part of their adherence to Order 890. We appreciate
the SDT’s careful consideration of our comments.

Northeast Utilities

No

NU agrees with the language of the proposed revision to Footnote b EXCEPT FOR bullet #3 which suggests
that non-consequential demand interruption could be used to mitigate reliability violations arising from the
NERC Category B contingency events (i.e., single element contingencies).

ERCOT

No

The introductory paragraph of footnote b includes policy language. Since this is a reliability standard-and not
a policy directive-the general narrative setting forth the desired policy goal of minimizing load-shedding is
misplaced. Including policy language can cloud the specific issues the standard attempts to address, and
ERCOT recommends deleting the first two sentences in the introductory paragraph.
The next sentence in the introductory paragraph goes on to state, generally, that demand may be interrupted
to "address BES performance requirements.” This phrase is vague. To which performance requirements
does this refer? The intent is not clear. If the intent is to generally recognize the need to shed load to respect

October 27, 2010

21

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
NERC standards and to allow flexibility for an entity to exercise discretion relative to meeting BES
performance requirements, then that intent should be clearly reflected in the language.
Furthermore, the last sentence of the introductory paragraph and the subsequent bullet points are arguably
inconsistent with this approach, because they could be viewed as removing an entity’s flexibility/discretion by
limiting the circumstances when load can be shed.
The second bullet point is unnecessary, because it is already apparent that interruptible demand/demand side
management programs can be used according to their terms. This could create confusion in that it could be
implied that, absent the need to use these to meet BES performance requirements, using them otherwise is
inconsistent with/not allowed under footnote b. Simply put, those products are not load shedding as
contemplated by this footnote. Therefore they should not be listed here.
With respect to the third bullet point, the phrase "demand that does not adversely impact overall BES
reliability" is not adequately defined, and provides opportunity for confusion. This is an ambiguous phrase
and can’t be linked back to objective NERC standards/requirements. The bullet points should avoid ambiguity
to mitigate ambiguity risk in audits.
In addition, the last part of the language in this bullet imposing an open and transparent stakeholder process
is unclear. What is the intent behind requiring review in a stakeholder process? If it is to establish the ability
of the entity to develop load shedding procedures beyond those explicitly contemplated in footnote b, ERCOT
questions if it is reasonable for the responsible entity to be required to get “permission” from stakeholders to
implement reliability measures related to its obligation as the functional entity. Again, the language simply is
not clear. Accordingly, ERCOT recommends this bullet point be removed. If it is retained, it should be revised
consistent with these comments to remove ambiguous language to mitigate potential confusion around the
meaning/scope of the footnote in the administration of the CMEP.
In addition, ERCOT recommends revising the draft footnote b to allow for planned Demand interruption as a
means of mitigation during interim periods when a unanticipated (such as unexpected demand growth or unit
retirements) or temporary change on the system occurs in a timeframe that is shorter than the time necessary
to plan and implement the system upgrades necessary to avoid the Demand interruption.
Finally, in the last paragraph of footnote b, it isn’t clear why “Transmission Service” was changed to
“transfers.” Firm transmission service is a service provided in some regions, and it provides relative value to
other types of services-e.g., non-firm and network. The mention of transmission service may also be
irrelevant in this footnote, since the allowance of its interruption doesn't also allow for load shedding.
Therefore, ERCOT recommends eliminating the last paragraph of footnote b.

ISO New England Inc.

October 27, 2010

No

ISO New England does not allow non-consequential load loss for first contingencies in Planning Analysis, and
as an overall matter, ISO-NE believes that the appropriate step is for NERC to modify the footnote in line with

22

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
the original FERC Order.
However, ISO-NE offers the following recommendation to improve the proposed language for footnote b if it is
to be retained similar to what has been proposed. In short, ISO-NE proposes changing the third sub-bullet,
because the provision is both unnecessary and inappropriate for a NERC Standard.
First, the sub-bullet is redundant, because the Commission has ordered that companies add to their Open
Access Transmission Tariffs an open and transparent planning process. If Transmission Planners establish
their system planning assessments through those processes, then there should be no question that the
Planner’s assessments have been effectively communicated to the region.
Second, the passive nature of the language (i.e., “where the application is subject to review and
acceptance...”) is unclear as it suggests that someone other than the Planning Coordinator/Transmission
Planner is responsible for determining what belongs in a long-term system assessment.
Including Demand-Side Management in the standard also appears redundant as Demand Response is used
as an asset in the same manner as generation resources.
b) When interruption of Demand is utilized within the planning process, such interruption is limited to:
1) Demand that is directly served by the elements that are removed from service as a result of the
Contingency.
2) Interruptible Demand or Demand-Side Management
3) Instances where the planned or controlled interruption of Demand results in System performance which
meets the requirements of Table 1 for Category B contingencies. When such Demand interruption is utilized
in an assessment, the use of such actions must be limited to small portions of the system, be operationally
achievable, be of limited duration, and be documented therein.

Entergy Services

No

Entergy disagrees with the proposed language in the third bullet for two reasons.
1. While Entergy supports the idea of “an open and transparent stakeholder process” regarding the use of
non-consequential load loss. It is unclear how such a process could be fairly implemented as competing
stakeholder interests could prevent resolution. Stakeholders should be defined as those stakeholders whose
load could be shed per footnote b, not any and all stakeholders.
2. The “is subject to review and acceptance” implies that some formal voting process would be required by
stakeholders. Is this the SDT’s intent? If so would such a process be developed as part of the standard or
would it be left up to TO’s? If non-consequential load loss was deemed an acceptable solution across a
SEAM, would the TO’s jointly serving the load need to agree?

October 27, 2010

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Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment

MidAmerican Energy

No

While the TPL note “b” approach has improved, MidAmerican has concerns that including the wording “review
and acceptance” goes beyond the FERC Order 890 order, process, and intent of including the open review
process. Therefore, to align with FERC Order 890, the “review and acceptance” should be replaced with
“subject to comment”. Anything more exceeds FERC Order 890 and the reason why the review process was
included. In the end, Transmission Owning and Operating entities must have final say in the operation of the
grid. Entities can comment, but cannot obstruct Transmission Owning and Operating entities from properly
operating the grid or reliability could be reduced.

United Illuminating Co

No

United Illuminating believes that for TPL Category B contingencies no planned or controlled (nonconsequential) interruption of firm demand should occur as a general philosophy for planning the Bulk Electric
System (BES). Recognizing there are certain areas of the BES that have unique circumstances that may
warrant an exception to this, UI suggests the addition of language that recognizes the limited application of
non-consequential load interruption with a process that requires a case-by-case acceptance of such
application by the Regional Entity or NERC.

New York Independent System
Operator

Yes

The NYISO agrees in principle with the proposed changes, but recommends the following modifications:
1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. The introductory paragraph is
immaterial to the requirement, and therefore unnecessary with the exception of the last sentence which starts
the bulleted list.
2. Interruptible demand is an operation tool and not a transmission planning tool, while Demand-Side
Management is typically embedded in the load forecast used in the planning process. The second bullet
therefore may not be necessary or applicable here, though it is helpful in making clear those are acceptable
forms of interruption.
3. The third bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system
and documentation expectations. Recommend removing reference to the application being subject to review
and acceptance in an open and transparent stakeholder process; this is inherent to all documentation and
does not need to be emphasized in a footnote.
4. In the last sentence of the last paragraph, “would” should be replaced by “must”.
5. The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC
Glossary dated April 20, 2010) Demand is: 1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An

October 27, 2010

24

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table. Possible rewording of footnote “b” to be considered: b) Under
the limited circumstances when interruption of Load is utilized within the planning process to address BES
performance requirements, such interruption is limited to: o Load that is directly served by the elements that
are removed from service as a result of the Contingency o Interruptible Load or Demand-Side Management o
Demand that does not adversely impact overall BES reliability where the circumstances for the use of such
Load interruption and alternatives evaluated are documented. Curtailment of firm transfers is allowed, when
coupled with the appropriate re-dispatch of available resources, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions must also be respected.

Midwest ISO

No

Overall, we believe the changes are reasonable. However, we propose to strike "and where the application is
subject to review and acceptance in an open and transparent stakeholder process.” Stakeholder review
processes should not be mandated through enforceable standards as they do not provide a clear benefit to
reliability. Further, FERC Order 890 already mandates an open and transparent process related to the
planning of the bulk electric system.

GDS Associates Inc.

No

We appreciate all the work conducted by SDT to adjust current footnote “b” however, we disagree with the
current approach as follows below:The definition does not go far enough with recognition that interruption of Demand should be mitigated if at all
possible. The previous language may have been inadequate, but the current language does not encourage
the TP to develop mitigation plans that could be implemented as an alternative to Demand interruption.
- Use of Interruptible Demand should only be implemented if the Transmission Planner can point to a contract
between the Transmission Provider and Transmission Customer that permits load curtailment
.- Under FERC Order 890, Conditional Firm transmission service can be granted for entities who voluntarily
acknowledge the right of the Transmission Provider to curtail their transaction or provide re-dispatch. This
should be the only transfer which can be utilized in the Planning Horizon for interruption of Demand for Note
b. Suggested language to find the balance point in the tone of this note is below:”An objective of the planning
process is to develop mitigation plans that do not call for the curtailment of Demand, as interruption of
Demand places specific customer groups at a reliability risk that varies from their counterparts in other areas
of the BES. There may be rare instances, however, where interruption of Demand can be considered a shortterm bridge to a mitigation plan which does not rely on negatively impacting certain customer segments.
When interruption of Demand is utilized within the planning process, such interruption is limited to: o Demand
that is directly served by the elements that are removed from service as a result of the Contingency, o

October 27, 2010

25

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
Interruptible Demand or Demand-Side Management, where the Customer has given explicit rights to the
Transmission Provider for curtailment of their Demand, o Demand, other than Interruptible Demand or
Demand-Side Management, that does not adversely impact overall BES reliability where the circumstances
describing the use of such Demand are documented, including alternatives evaluated; where the LoadServing Entity who has responsibility for serving such Demand has agreed to the curtailment, and where the
application is subject to review and acceptance in an open and transparent stakeholder process. Curtailment
of Firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch per the terms and conditions of the confirmed transmission service request between the
Transmission Customer and Transmission Provider, where it can be demonstrated that Facilities remain
within applicable Facility Ratings and the re-dispatch does not result in the shedding of and firm Demand.
Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in
those regions would also be respected. In addition, any Conditional Firm transfers may be curtailed, in
accordance with the terms and conditions of the confirmed transmission service request between the
Transmission Customer and Transmission Provider.”

Kansas City Power & Light

No

KCPL appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable
proposal for clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also
commend NERC staff for convening an industry technical conference to discuss the topic and FERC staff for
their participation in the technical conference as the industry carefully considered various perspectives.
Although the proposed footnote B is much improved from the prior draft proposals, KCPL proposes is to strike
the text following the semicolon in the third bullet item which states “and where the application is subject to
review and acceptance in an open and transparent stakeholder process.” This text may be intended as
explanatory but has the appearance of mandating an approval process that will be auditable through the TPL
reliability standards. The statement is not needed within the framework of mandatory reliability requirements
as FERC Order 890 already mandates an open and transparent process related to the planning of the bulk
electric system. FERC via the 890 Final Rule modified the pro forma Open-Access Transmission Tariff to
require open and transparent stakeholder process to better ensure no undue discrimination and access to the
transmission system. The Final Rule beginning at paragraph 418 discusses reform to the Coordinated, Open
and Transparent Planning of the transmission system. The Commission direction included eight planning
principles required to be within the open process - one of which is dispute resolution. It should be well
understood that the transmission planner and planning coordinator share and disseminate all of their planning
study results and proposed corrective actions - including the proposed use of Demand interruption - as part of
their adherence to Order 890.

Puget Sound Energy

Yes

PSE agrees with the foot note b as stated. As it states for any category B outage there wouldn't be any nonconsequential load loss allowed unless a full study is performed with evaluation of alternatives and is
approved by stakeholders. Also, one could curtail firm transfers if re-dispatch of resource is possible.

October 27, 2010

26

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
However, there is still some ambiguity in when approval from stakeholders (time-line) should be sought and
who the stakeholders could be (customers, effected utilities etc.). Hence, PSE would like to revise the
footnote by adding the following to the end of the footnote, ".... at least 2 years prior to the implementation. All
the affected parties must review and agree upon the loss of demand proposal."

Southern California Edison
Company

Yes

SCE appreciates the efforts of the NERC Standards Drafting Team and believes that the team has admirably
worked to meet FERC's expectations.SCE would suggest that Footnote "b" be revised to include a semicolon(;) after the first sub-paragraph and a semi-colon(;) followed by an "and" after the second subparagraph, to convey that the three sub-paragraphs are alternative, rather than additive methods for satisfying
the requirements for "interruptions."

Idaho Power

Yes

footnote 'b' is silent with respect to planned removal from service of certain generators. I believe there are
many conditions out there where a single contingency can initiate a planned (RAS-initiated) removal of
generation. The fact that this is mentioned in footnote 'c', under multiple contingencies, begs the need for
futher elaboration/discussion of this option under single contingencies in footnote 'b'.

Manitoba Hydro

Yes

The changes to Table 1 Note b proposed by the SDT for this second posting are a reasonable approach to
the issue of interrupting of “Firm Demand”. The requirement to evaluate alternatives to dropping of Firm
Demand in a transparent stakeholder process should provide the verification of cost over benefit on a case by
case basis. I propose the following editorial changes: 1. The change of “Firm Transmission Services” made in
Table 1 should be also be made in each TPL standard as R1 refers to “projected Firm (non-recallable
reserved) Transmission Services.2. Since “Firm Demand” is a defined term, ensure it is capitalized throughout
the standard. There is one instance where it is not.

California ISO

Yes

1) Regarding the 2nd bullet provision, we suggest: Interruptible Demand or Demand-Side Management that
has been reviewed and approved by the Planning Authority.
2) Regarding the 3rd bullet provision, we suggest: Demand interruption that does not adversely impact
overall BES reliability....
3) Also regarding the 3rd bullet provision, we suggest replacing acceptance with clarification to read “where
the application is subject to review and clarification in an open and transparent stakeholder process."

Xcel Energy

October 27, 2010

Yes

Xcel Energy supports the new interpretation that would allow curtailment of firm transfers or demand for
limited conditions where the integrity of bulk electric system is not compromised. However Xcel Energy seeks
some clarification regarding the following: The 3rd bullet point in footnote b will need to clarify whether the
demand interruption can be done after the contingency, or before the contingency. If it is allowed after the

27

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
contingency, then the standard would allow violation of voltage or thermal loading criteria for a brief period,
after contingency and, before demand curtailment happens. Is this acceptable based on the new
interpretation?
Since TPL-002 standard deals with NERC Category B contingencies, and footnote b states that curtailment of
firm transfers is allowed, it should be clarified if this curtailment is allowed before or after the contingency. If
the curtailment is allowed only after the contingency, then the system would be in violation of the thermal or
voltage criteria for a brief period till the generation is re-dispatched. Is this allowed by the new interpretation?
If curtailment is only allowed in preparation of the contingency, then the firm transfers would be curtailed
during system intact conditions, in preparation for the first contingency, resulting in violation of TPL-001
standard. Is this allowed by the new interpretation?

PPL Corp

Yes

PPL believes that Footnote b as described in TPL-002-1b, Draft 2, August 30, 2010 is fine provided an
accompanying Requirement (with appropriate VRF and VSL) and Measure is added to the TPL standard(s) to
require and document notification of the affected Demand parties and the involvement of the affected
Demand parties in an open process as described by Footnote b, third bullet.

Duke Energy

Yes

Duke Energy strongly supports this revised footnote ‘b’. We believe that it provides for appropriate
consideration of stakeholder input in decision-making for local reliability issues, while maintaining the
reliability of the Bulk Electric System.

ITC

Yes

The proposed language for the new TPL-001-1 Table 1 footnote b is acceptable to ITC.

Bonneville Power Administration

Yes

Dominion

Yes

IRS Standards Review
Committee

Yes

IRC Standards Review
Committee

Yes

Arizona Public Service Company

Yes

ERCOT ISO

Yes

October 27, 2010

28

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Georgia Transmission
Corporation

Yes

American Electric Power

Yes

Independent Electricity System
Operator

Yes

Pacific Gas and Electric Co.

Yes

October 27, 2010

Question 1 Comment

29

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on
the 3rd posting for Project 2010-11: TPL Table 1 Order. These standards were posted for a
45-day public comment period from November 19, 2010 through January 5, 2011. The
stakeholders were asked to provide feedback on the standards through a special Electronic
Comment Form. There were 27 sets of comments, including comments from more than 67
different people from approximately 30 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.

http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
The SDT reviewed all of the comments received and has made a clarifying change to the structure of the
footnote to address industry concerns as to the intent of the SDT. No contextual changes have been
made to the footnote. Therefore, the SDT is recommending that this project be moved to a recirculation
ballot.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is:
(1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated;
and where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Index to Questions, Comments, and Responses
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply
with a FERC directive which required the ERO to clarify TPL-002-0, Table 1 footnote ‘b’, regarding the planned or controlled interruption of electric supply
where a single contingency occurs on a transmission system. Do you agree
with the proposed changes and if not, please provide specific reasons for your
disagreement.…. .............................................................................................. 7

2

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

2

Northeast Power Coordinating Council

Additional Member Additional Organization

Region

3

4

5

6

7

8

9

10

X

Segment
Selection

1.

Al Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Greg Campoli

New York Independent System Operator

NPCC

2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Dean Ellis

Dynegy Generation

NPCC

5

8.

Brian Evans-Mongeon

Utility Services

NPCC

8

9.

Mike Garton

Dominion Resources Services, Inc.

NPCC

5

10.

Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

11.

Kathleen Goodman

ISO - New England

NPCC

2

12.

Chantel Haswell

FPL Group, Inc.

NPCC

5

13.

David Kiguel

Hydro One Networks Inc.

NPCC

1

3

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

14.

Michael R. Lombardi

Northeast Utilities

NPCC

1

15.

Randy MacDonald

New Brunswick System Operator

NPCC

2

16.

Bruce Metruck

New York Power Authority

NPCC

6

17.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18.

Robert Pellegrini

The United Illuminating Company

NPCC

1

19.

Si Truc Phan

Hydro-Quebec TransEnergie

NPCC

1

20.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC

3

2.

Group

Charles W. Long

SERC Planning Standards Subcommittee

Additional Member Additional Organization

Region

X

Pat Huntley

SERC Reliability Corporation

SERC

10

2.

Bob Jones

Southern Company Services

SERC

1

3.

Darrin Church

Tennessee Valley Authority

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative SERC

1

5.

John Sullivan

Ameren Services Company

SERC

1

6.

Phil Kleckley

South Carolina Electric & Gas Co. SERC

1

Group
Additional Member

Carol Gerou

MRO's NERC Standards Review
Subcommittee

Additional Organization

4

5

6

7

8

9

10

X

Segment
Selection

1.

3.

3

X

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration

MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

11. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12. Scott Nickels

Rochester Public Utilties

MRO

4

13. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

14. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

2

3

4

5

6

4.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

5.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

X

6.

Individual

Andy Tillery

Southern Company

X

X

7.

Individual

Aaron Staley

Orlando Utilities Commission

X

8.

Individual

Greg Rowland

Duke Energy

X

9.

Individual

Si Truc PHAN

Hydro-Quebec TransÉnergie

X

10.

Individual

Tim Ponseti, VP

TVA Trasnmission Plannning & Compliance

X

11.

Individual

Alex Rost

New Brunswick System Operator

12.

Individual

Joe Petaski

Manitoba Hydro

13.

Individual

Bernie Pasternack

Transmission Strategies, LLC

Individual

Michael A. Curtis,
General Counsel

Mohave Electric Cooperative

Individual

David Thorne

Pepco Holding Inc

14.

15.

7

8

9

10

X
X

X

X

X

X

X

X

X

X
X

X
X

X
X

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

16.

Individual

John Sullivan

Ameren

X

X

X

X

17.

Individual

Thad Ness

American Electric Power

X

X

X

X

18.

Individual

Bob Casey

Georgia Transmission Corporation

X

19.

Individual

Alice Ireland

Xcel Energy

X

X

X

X

20.

Individual

Saurabh Saksena

National Grid

X

X

21.

Individual

Andrew Z. Pusztai

American Transmission Company

X

22.

Individual

Jason L. Marshall

Midwest ISO

23.

Individual

Michael Lombardi

Northeast Utilities

24.

Individual

Dan Rochester

Independent Electricity System Operator

X

25.

Individual

Gregory Campoli

New York Independent System Operator

X

26.

Individual

Kathleen Goodman

ISO New England Inc

X

27.

Individual

Harold Wyble

Kansas City Power & Light

7

8

9

10

X
X

X

X

X

X

X

X

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with a FERC directive which required
the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system. Do you agree with the proposed changes
and if not, please provide specific reasons for your disagreement.

Summary Consideration: The SDT reviewed all of the comments received and has made a clarifying change to the structure of the footnote
to address industry concerns as to the intent of the SDT. No contextual changes have been made to the footnote.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand
following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is
recognized [llh1]that Firm Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a result of the
Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may
need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the planning process
to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the
Demand interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder
comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can
be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would
also be respected.

Organization
SERC Planning Standards
Subcommittee

Yes or No
No

Question 1 Comment
The PSS agrees that the proposed language for footnote b provides some additional clarity. While we
generally support the concept, we have concerns that the phrase “is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments” remains ambiguous and
should be clarified by limiting stakeholder input to those who have load at risk or local regulators obligated to

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
act on their behalf.
Revise the first sentence of the last paragraph to read: “To prepare for a second contingency, curtailment of
firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch,
where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand.”The comments expressed herein represent a consensus of the
views of the above-named members of the SERC EC Planning Standards Subcommittee only and should not
be construed as the position of SERC Reliability Corporation, its board, or its officers.

Response: The stakeholder process needs to be open and transparent but it is up to the entity to establish the process and whom it may include. No change
made.
As drafted, footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language recognizes that
System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be utilized for a limited
time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan
to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm
transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the footnote. No
change made.
Xcel Energy

No

As this is currently drafted, planners would be required to host a forum with stakeholders to discuss
hypothetical actions that may be taken in an emergency. We do not see the value in this, nor is it clear who
would be considered stakeholders that should attend this forum. For example, we assume it would be the
transmission owner’s meeting with distribution providers to discuss the possibility of load shedding. Would
that be adequate? Xcel Energy is both a Transmission Planner and a Distribution Provider. In this case
would the stakeholder be the end user? This should be struck or more clearly defined.

Response: The stakeholder process needs to be open and transparent but it is up to the entity to establish the process and whom it may include. No change
made.
New York Independent System
Operator

No

1. Proposed revised footnote language:b) It is recognized that Demand will be interrupted if it is directly
served by the Elements removed from service as a result of the Contingency. When interruption of
Demand is utilized within the planning process to address BES performance requirements, such
interruption is limited to: o Interruptible Demand or Demand-Side Management o Circumstances where
the uses of firm Demand interruption not directly interrupted by the contingency are documented,
including alternatives evaluated; and where the firm Demand interruption is subject to review in an open
and transparent stakeholder process. Curtailment of firm transfers is allowed, when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that Facilities

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
remain within applicable Facility Ratings and the re-dispatch does not result in the interruption of any firm
Demand.
2. Comments:There are generic concerns with the footnote as amended that must be addressed. The first
is the use of the term “Demand”. It is very unclear throughout the footnote whether or not the term
Demand includes Interruptible Demand or Demand-Side Management. It is suggested that interruption of
Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly
show the permitted use of that option for load shedding.
3. Further confusion is introduced through the use of the term “firm Demand” in some locations. It is unclear
how this is different than the defined term “Firm Demand” and what the implications of the term “firm
Demand” are.
4. The first and third sentences of the first paragraph are unnecessary and should be deleted. However, if
they are to be retained, the first sentence is unacceptable in its current state. In some instances,
Interruptible Demand or Demand-Side Management are utilized in lieu of transmission additions. These
can be considered as acceptable mitigation and there is no justification to minimize their use. Therefore
some clarification to the term Demand in the first sentence must be made.
5. It is unclear whether the second bullet includes Demand which is interrupted by the elements removed
from service. Clarification should be made such that Demand which is interrupted by the elements
removed from service should not be included in this bullet.
6. The second portion of the second bullet should be deleted as it is unncessary: “and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing
stakeholder comments.” If this is to be retained, the very last portion should be deleted “that includes
addressing stakeholder comments”. The term “addressing” is unclear. This can be misconstrued to infer
that plans must be changed in response to stakeholder comments. This may be inappropriate and may
be impossible if conflicting comments are received. It may also create a new standard that all comments
must be “addressed”, which may not be a part of the stakeholder process across NERC’s footprint.
7. The first sentence of the paragraph under the two bullets seems to prevent a situation where a
combination of re-dispatch and the interruption of Demand are utilized. This restriction could prevent a
situation where the use of re-dispatch decreases the amount of Demand which must be interrupted. This
footnote should not discourage such adjustments which actually increase the reliability of service to end
users.
8. This same sentence also uses the term “shedding of firm Demand”. This should be replaced with
“Demand interruption” such that it is consistent with the second bullet; otherwise an unnecessary new
term has been introduced.

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
9. The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause
reliability concerns in another area while addressing your own. This same thought would have to be
added to multiple NERC standards if it was added here, otherwise it would infer that such actions are
acceptable in all other standards.

Response: 1. See response to National Grid #1 in ballot comment responses.
2. See response to National Grid #1 in ballot comment responses.
3. See response to National Grid #6 in ballot comment responses.
4. The SDT has reorganized the footnote to clarify its intent and address the issues raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result [llh2]in the shedding of any firm Demand. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
5. See response to National Grid #2 in ballot comment responses.
6. See response to National Grid #4 in ballot comment responses.
7. The SDT has reorganized the footnote to clarify its intent and address the issues raised.
8. The SDT has reorganized the footnote to clarify its intent and address the issues raised.

10

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

9. See response to National Grid #7 in ballot comment responses.
ISO New England Inc

No

1. The following comments are provided in regard to this proposal. The first and third sentences of the first
paragraph are unnecessary. While we agree with the concept, it is unclear as to how inclusion of these
sentences in a standard creates a measureable requirement.
2. There are generic concerns with the footnote as currently proposed. The first is the use of the term
“Demand.” It is unclear whether the term Demand includes Interruptible Demand and Demand-Side
Management. It is suggested that interruption of Demand be clarified to exclude Interruptible Demand
and Demand-Side Management to more clearly show the permitted use of those options.
3. The second concern is that it is unclear whether the second bullet includes Demand which is interrupted
by the elements removed from service. Clarification should be made such that Demand which is
interrupted by the elements removed from service should not be included in this bullet.
4. The third is that not all areas have stakeholder processes. Documenting the use of Demand Interruption
should be sufficient without requiring stakeholder review. Therefore the second portion of the second
bullet “including alternatives evaluated; and where the Demand interruption is subject to review in an
open and transparent stakeholder process that includes addressing stakeholder comments” is
unnecessary and should be deleted. “Addressing stakeholder comments” introduces undefined actions
which may be required in response to the comments. For those areas that already have stakeholder
processes, stakeholder comments are by definition addressed. As a result, at a minimum “that includes
addressing stakeholder comments” should be deleted. Furthermore, for areas that do not have
stakeholder processes, so long as they publish their studies impacted parties are aware of the role of
demand response.
5. The fourth is that the second paragraph seems to be restricting the use of Demand interruption for the
sake of Firm Transfer reduction. This can be stated directly without adding the confusion of re-dispatch.
By coupling re-dispatch with a constraint of not shedding Demand, the paragraph also creates confusion
as to what to do in a situation where the amount of Demand that is allowed to be shed in the first
paragraph could be reduced with re-dispatch. Would re-dispatch not be allowed? We suggest that the
paragraph be rewritten as follows: “Curtailment of firm transfers is allowed to meet BES performance
requirements and meet applicable Facility Ratings, where it can be demonstrated it does not result in the
interruption of any Demand (other than Interruptible Demand or Demand Side Management).”
6. The fifth is if the term ‘firm demand’ survives the proposed changes; is there an intended distinction
between the use of the term “firm Demand” and the defined term “Firm Demand”? If these terms are
intended to be differently, it is unclear what the term “firm Demand” represents.
7. The final comment is that the last sentence of footnote B is unnecessary and should be deleted. It is

11

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
never acceptable to cause reliability concerns in another area while addressing your own. This same
thought would have to be added to multiple NERC standards if it was added here, otherwise it would infer
that such actions are acceptable in all other standards.
8. If the first and third sentences must be retained the following wording for the footnote is proposed:b) An
objective of the planning process should be to minimize the likelihood and magnitude of interruption of
Demand, (excluding Interruptible Demand or Demand-Side Management), following Contingency events.
However, it is recognized that Demand will be interrupted if it is directly served by the Elements removed
from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need to
be interrupted to address BES performance requirements. When interruption of Demand is utilized within
the planning process to address BES performance requirements, such interruption is limited to: o
Interruptible Demand or Demand-Side Management o Circumstances where the uses of Demand
interruption not directly interrupted by the contingency are documented. Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can be
demonstrated it does not result in the interruption of any Demand (other than Interruptible Demand or
Demand Side Management).

Response: 1. The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to
provide a balance between flexibility and consistency across NERC. No change made.
2. See ballot response to NPCC #1.
3. See ballot response to NPCC #2.
4. The SDT believes that in situations where an entity’s planning studies require the interruption of firm load to remain within BES Facility ratings that the entity
needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those decisions have
the ability to review and comment on those plans. No change made.
5. See ballot response to NPCC #5.
6. The SDT has corrected the indicated errors.
7. See ballot response to NPCC #6.
8. The SDT has reorganized the text in the footnote to address this concern.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited

12

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
Northeast Power Coordinating
Council

No

There is concern with the use of the term Demand. It is unclear throughout the footnote whether or not the
term Demand includes Interruptible Demand or Demand-Side Management. It is suggested that interruption
of Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly
show the permitted use of Load shedding.
It is unclear whether the second bullet includes Demand which is interrupted by the elements removed from
service. Clarification should be made such that Demand which is interrupted by the elements removed from
service should not be included in this bullet.
Language that mitigation of Load and/or Demand interruption should be pursued within the planning process
should be reinstated as reinforcement of a Transmission Providers’ planning obligations to their load
customers, and system operations.
Footnote ‘b’ should be made to read as follows:b) An objective of the planning process is to minimize the
likelihood and magnitude of interruption of Load and/or Demand following Contingency events. Interruption of
Load and/or Demand is discouraged and all measures to mitigate such interruption should be pursued within
the planning process. However, it is recognized that Load and/or Demand will be interrupted if it is directly
served by the elements automatically removed from service by the Protection System as a result of a
Contingency. Furthermore, in extraordinary circumstances within the planning process Load and/or Demand
may need to be interrupted to address BES performance requirements. When interruption of Load and/or
Demand is utilized within the planning process to address BES performance requirements, such interruption
is limited to: o Circumstances where the use of Load and/or Demand interruption are documented,
including alternatives evaluated; and where the Load and/or Demand interruption is made available for review
in an open and transparent stakeholder process.If Load and/or Demand interruption is necessary, planning
should indicate the amount needed, and not specify how it would be obtained. What Load and/or Demand is

13

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
interrupted is an operational decision.
Additional comments not included in the material listed for footnote ‘b’ on the Comment Form. In the
paragraph below the bullets in footnote ‘b’, confusion is introduced through the use of the term “firm Demand”.
It is unclear how this is different than the defined term “Firm Demand” and what the implications of the term
“firm Demand” are. This footnote should not discourage such adjustments which actually increase the
reliability of service to end users. The last sentence of footnote ‘b’ is unnecessary and should be deleted. It
is never acceptable to cause reliability concerns in another area while addressing your own.

Response: This comment is identical to the one made by NPCC in the ballot and the SDT has answered the comment in that forum.
Arizona Public Service Company

No

It is not clear whether both bullets under "footnote b" have to be met or only one of the two have to be met. It
is suggested that the standard be very clear about this.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Southern Company

No

Southern Company is voting "no" on the footnote b ballot because of concerns that the reliability of firm
transfers could be compromised. The existing Table I Transmission System Standards, which have been in
place as early as the 1997 NERC Planning Standards, do not allow Loss of Demand or Curtailed Firm
Transfers under single (Category B) contingencies. Footnote B addressed two areas: 1) the loss of radial or
local network load, which Southern Company agrees that the drafting team has appropriately clarified and 2)
preparing for the next contingency, which Southern Company does not agree has been appropriately
clarified.Southern Company believes the proposed wording "Curtailment of firm transfers is allowed, when
coupled with the appropriate re-dispatch of resources obligated to re-dispatch" now allows for the curtailment
of firm transfers for single contingencies, whereas Southern Company did not believe this was previously
permitted under the standards. Southern Company interprets the new language to allow a planner to curtail
firm transfers (generation) to address a single contingency. Southern Company interpreted the original
language to not permit the curtailment of firm transfers (generation) for a single contingency, but rather that a
planner would develop a suitable transmission reinforcement or other mitigation. Southern Company is
concerned that the proposed language could result in a degradation in the dependability of firm transfers
impacting the reliability of those customers who rely upon them. Southern Company agrees that a system
reconfiguration including the redispatch of generation is appropriate when preparing for a second contingency
(Category C).Therfore, a distinction is needed between what is allowed in response to a first contingency and
what is allowed to be prepared for a second contingency. The curtailment of firm transfers should not be
allowed as a response to the first contingency. This practice would undermine the concept of firm transfers.
The curtailment of firm transfers should only be allowed in footnote b as a system adjustment to be prepared
for a second contingency. We propose the following to clarify that curtailments are permitted only to prepare

14

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
for the second contingency. "To prepare for the next contingency, curtailment of firm transfers is allowed,
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch".

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Orlando Utilities Commission

No

The current language provides a balance between the end goal of reliablity (no load loss for B events) and the
practical constraint that project cost may outweigh the benefit. Two things are unclear though. Item one: The
standard team should clarify if the bullets under note B are intended to be an AND (both conditions met) or an
OR (either condition met). As currently written it is not clear.
Item #2: The section under firm transfers is in conflict with the section above. If Demand is being curtailed
under the first or second bullet and it’s served by firm service then service should also be curtailed, however
as written any demand served by firm service could not be curtailed.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Duke Energy

Yes

The effective date in the Implementation Plan needs to be changed to match the Effective Date in the
standards, in order to clarify the allowed interruption of Non-consequential load before the new Footnote ‘b’
takes effect.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Hydro-Quebec Transenergie

Yes

Paragraph should be more clear as:b) An objective of the planning process should be to minimize the
likelihood and magnitude of interruption of Demand following Contingency events. However, it is recognized
that Demand will be interrupted if it is directly served by the Elements removed from service as a result of the
Contingency. Furthermore, in limited circumstances within the planning process, Demand may need to be
interrupted to address BES performance requirements. In such case : o Only Interruptible Demand or
Demand-Side Management are allowed;o Circumstances where the uses of Demand interruption is needed
shall be documented, compared to alternatives, and reviewed in an open and transparent stakeholder
process that address stakeholder comments. Curtailment of firm transfers is allowed, when coupled with the
appropriate and necessary re-dispatch of resources where it can be demonstrated that this does not result in
the shedding of any firm Demand and that Facilities remain within applicable Facility Ratings, including
Facilities external to the Transmission Planner’s planning region when they are relied upon.

Response: The SDT believes that the changes indicated in your proposed footnote do not add any additional clarity. However, the SDT has reorganized the
footnote to clarify its intent.

15

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
TVA Trasnmission Plannning &
Compliance

No

TVA appreciates the SDT’s efforts to clarify and improve this complex and challenging area. However, as
mentioned in our last comments regarding footnote b, TVA still believes that the SDT’s proposal is still
focusing more on reliability of local loads than on the overall reliability of the BES. Reliability of local loads
should be addressed outside the TPL standards and therefore should not be used/referenced in footnote b.
Existing stakeholder processes (referred to in the SDT proposal) typically focus on larger system issues and
not on local load serving. TVA believes that some local load should be allowed to be dropped in order to
maintain BES reliability. Instead of the proposed footnote b, TVA suggests that the SDT define a “local area”
with guidelines detailing the reliability requirements for these local area loads. This would separate the local
area load requirements from the BES requirements in the TPL standards.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
New Brunswick System Operator

No

NBSO agrees with the principles of the current version of the proposed footnote, as far as NBSO’s
interpretation of the footnote is correct. NBSO has the following detailed comments:1. The first paragraph
contains many general statements that attempts to capture essential planning principles. NBSO feels that
such language is not suited for a footnote. NBSO suggests re-wording of the first paragraph to
state:Interruption of Demand may be utilized within the planning process to address BES performance
requirements. Such cases are limited to:NBSO also suggests turning the phrase that addresses Demand lost
that was served by elements removed from service as a result of a Contingency into a bullet item. NBSO feels

16

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
that this adds clarity since all of the acceptable instances of Demand interruption are now listed as bulleted
items.2. NBSO interprets that the currently proposed footnote allows for the two bulleted options to be used
exclusively or in combination. Thus for clarification NBSO suggests adding “or” after each bulleted item, with
the exclusion of the final bulleted item.3. NBSO suggests removing the last sentence of the last paragraph.
Likely all industry members understand that causing reliability concerns in other areas is never acceptable.
This principle is not limited to the standard in question, and thus such a statement could require the update of
other standards.4. NBSO interprets that the use of the word “Demand” in the second bullet of the proposed
footnote is referring to use of Firm Demand since the first bullet covers the other types of Demand (Demand =
Firm Demand + Interruptible Demand). As such NBSO suggests replacing “Demand” with “Firm Demand” in
the second bullet.5. NBSO feels that the statement “that includes addressing stakeholder comments” should
be removed from the last phrase of the second bullet. An open and transparent stakeholder process should
adequately address stakeholder comments and concerns. Explicitly specifying that all stakeholder comments
be addressed may add undue burden if the word “address” is misconstrued. The task of addressing
stakeholder comments is more appropriately addressed and defined in each area’s respective process.6.
NBSO suggests replacing the word “shedding” with “interruption” in the last phrase of the last paragraph to
remain consistent with the rest of the proposed footnote. NBSO also suggests capitalizing “firm” in the term
“Firm Demand” to remain consistent with the NERC glossary of terms.7. There is no term “transfers” in the
NERC glossary of terms. Perhaps some other defined term from the glossary could be used in lieu of
“transfers” (e.g. Firm Transmission Service).Taking into account the NBSO comments, the footnote could
read as follows:b) Interruption of Demand may be utilized within the planning process to address BES
performance requirements. Such cases are limited to:-Demand directly served by Elements removed from
service as a result of a Contingency, or-Use of Interruptible Demand or Demand-Side Management, orInterruption of Firm Demand when acceptable circumstances for such interruptions are documented
(including alternatives evaluated), and where the Firm Demand interruption is subject to review in an open
and transparent stakeholder process.Curtailment of Firm Transmission Service is allowed when coupled with
the appropriate re-dispatch of resources obligated to do so, and it can be demonstrated that Facilities remain
within applicable Facility Ratings and there is no additional interruption of Firm Demand.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Manitoba Hydro

No

The last bullet should be made clearer by adding the words “in jurisdictions” before the word “where”. Not all
jurisdictions are mandated to have a stakeholder process, so the standard should be clearly written to
recognize this situation. "Circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and IN JURISDICTIONS where the Demand interruption is subject to review in an
open and transparent stakeholder process that includes addressing stakeholder comments."

17

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Ameren

No

We agree with the statement that an objective of the planning process should be to minimize the likelihood
and magnitude of interruption of Demand following single contingency events. While we appreciate the
drafting team’s efforts in removing the need for acceptance by other parties in the stakeholder process, we
still feel that language in the second bullet of the revised footnote b should be modified to remove all
references to an open and transparent stakeholder process. Existing RTO stakeholder processes that we are
aware of focus on larger system issues, rather than on local load serving issues. Therefore, we believe that
the load serving issues following single contingency events are issues between the customer and the utility,
and should be addressed in one-on-one forums between those entities.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
National Grid

No

National Grid supports the direction the drafting team has taken. However, it has a few concerns with the
language of the footnote as amended. 1. Use of the term “Demand”: In the first sentence, it is unclear
whether the term Demand includes Interruptible Demand and Demand-Side Management. It is suggested
that interruption of Demand be clarified to exclude Interruptible Demand or Demand-Side Management. 2. It
is unclear whether the second bullet includes Demand which is interrupted by the elements removed from
service. Clarification should be made such that Demand which is interrupted by the elements removed from
service should not be included in this bullet. 3. National Grid also suggests changing “Demand interruption” to
“interruption of Demand” in second bullet under “b)” to avoid awkward and incorrect phasing.4. ‘Addressing
stakeholder comments’ introduces undefined actions which may be required in response to the comments. If
‘Demand interruption is subject to review in an open and transparent stakeholder process’, then stakeholder
comments will be addressed without creating an undefined commitment to require it. As a result, “that
includes addressing stakeholder comments” should be deleted. 5. The second paragraph seems to be
restricting the use of Demand interruption for the sake of Firm Transfer reduction. This can be stated directly
without adding the confusion of re-dispatch. By coupling re-dispatch with a constraint of not shedding
Demand, the paragraph also creates confusion as to what to do in a situation where the amount of Demand
that is allowed to be shed in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be
allowed? National Grid suggests that the paragraph be rewritten as follows: ‘Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can be
demonstrated it does not result in the interruption of any Demand (other than Interruptible Demand or
Demand Side Management).’ 6. National Grid seeks clarification if there is an intended distinction between
the use of the term “firm Demand” and the defined term “Firm Demand” or is that just a typo?7. The last
sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause reliability
concerns in another area while addressing your own. This same thought would have to be added to multiple

18

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
NERC standards if it were added here, otherwise it would infer that such actions are acceptable in all other
standards.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Northeast Utilities

No

The revised language of Footnote b suggests that non-consequential demand interruption (load that is not
directly served by the elements removed from service as a result of the contingency) could be used to
mitigate reliability concerns arising from NERC Category B contingency events (i.e., single element
contingencies). This language seems to encourage operational workarounds and adds burdens for operators
of the system. NU believes this is not consistent with planning a highly reliable bulk electric system and thus
does not support this weaker language.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Kansas City Power & Light

Yes

MRO's NERC Standards Review
Subcommittee

Yes

PacifiCorp

Yes

Transmission Strategies, LLC

Yes

Mohave Electric Cooperative

Yes

Pepco Holding Inc

Yes

American Electric Power

Yes

Georgia Transmission
Corporation

Yes

American Transmission
Company

Yes

appreciates the efforts of the SDT and supports revision of TLP-002-0 Table 1 footnote “b” as stated in this
draft.

19

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Midwest ISO

Yes

Independent Electricity System
Operator

Yes

Question 1 Comment

Response: Thank you for your support.

20

Consideration of Comments on Successive Ballot — Project 2010-11 – TPL Table 1, Footnote b
Successive Ballot Dates: 12/27/2010 - 1/5/2011
Summary Consideration:
The SDT reviewed all of the comments received and has made a clarifying change to the structure of the footnote to address industry concerns as to the intent of
the SDT. No contextual changes have been made to the footnote. Therefore, the SDT is recommending that this project be moved to a recirculation ballot.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is subject
to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 609-452-8060 or at
1
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.

Balloter
Richard J.
Mandes
1

Company
Alabama Power
Company

Segment
3

Vote
Negative

Comment
Southern Company is voting "no" on the footnote b ballot because of concerns that the reliability
of firm transfers could be compromised. The existing Table I Transmission System Standards,

The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.

Balloter
Anthony L
Wilson

Company
Georgia Power
Company

Segment
3

Vote

Comment

Negative

which have been in place as early as the 1997 NERC Planning Standards, do not allow Loss of
Demand or Curtailed Firm Transfers under single (Category B) contingencies. Footnote B
addressed two areas: 1) the loss of radial or local network load, which Southern Company agrees
Don Horsley
Mississippi Power
3
Negative
that the drafting team has appropriately clarified and 2) preparing for the next contingency, which
Southern Company does not agree has been appropriately clarified. Southern Company believes
the proposed wording "Curtailment of firm transfers is allowed, when coupled with the appropriate
Horace
Southern
1
Negative
re-dispatch of resources obligated to re-dispatch" now allows for the curtailment of firm transfers
Stephen
Company Services,
for single contingencies, whereas Southern Company did not believe this was previously permitted
Williamson
Inc.
under the standards. Southern Company interprets the new language to allow a planner to curtail
firm transfers (generation) to address a single contingency. Southern Company interpreted the
original language to not permit the curtailment of firm transfers (generation) for a single
contingency, but rather that a planner would develop a suitable transmission reinforcement or
other mitigation. Southern Company is concerned that the proposed language could result in a
degradation in the dependability of firm transfers impacting the reliability of those customers who
rely upon them. Southern Company agrees that a system reconfiguration including the redispatch
of generation is appropriate when preparing for a second contingency (Category C). Therfore, a
distinction is needed between what is allowed in response to a first contingency and what is
allowed to be prepared for a second contingency. The curtailment of firm transfers should not be
allowed as a response to the first contingency. This practice would undermine the concept of firm
transfers. The curtailment of firm transfers should only be allowed in footnote b as a system
adjustment to be prepared for a second contingency. We propose the following to clarify that
curtailments are permitted only to prepare for the second contingency. "To prepare for the next
contingency, curtailment of firm transfers is allowed, when coupled with the appropriate redispatch of resources obligated to re-dispatch".
Response: The SDT has changed the wording „coupled with‟ to „achieved through‟ to better clarify the SDT‟s intent.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand

2

Balloter

Company

Segment

Vote

Comment

interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
As drafted, footnote „b‟ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language recognizes
that System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be utilized for a
limited time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the Transmission Planner
can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not obligated to re-dispatch,
the firm transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the
footnote. No change made.
Jennifer
Ameren Energy
6
Negative
We agree with the statement that an objective of the planning process should be to minimize the
Richardson
Marketing Co.
likelihood and magnitude of interruption of Demand following single contingency events. While we
appreciate the drafting team‟s efforts in removing the need for acceptance by other parties in the
Kirit S. Shah
Ameren Services
1
Negative
stakeholder process, we still feel that language in the second bullet of the revised footnote b
should be modified to remove all references to an open and transparent stakeholder process.
Existing RTO stakeholder processes that we are aware of focus on larger system issues, rather
than on local load serving issues. Therefore, we believe that the load serving issues following
single contingency events are issues between the customer and the utility, and should be
addressed in one-on-one forums between those entities.
Response: The SDT disagrees that this should be handled through two party interactions. The SDT believes that in situations where an entity‟s planning
studies require the interruption of Firm Demand to remain within BES Facility Ratings that the entity needs to share those plans in an open and transparent
stakeholder process to ensure that other parties that may be impacted by those decisions have the ability to review those plans. No change made.
Steven Norris APS
3
Negative
It is not clear whether both bullets under “footnote b” have to be met or only one of the two have
to be met. It is suggested that the standard be very clear about this
Mel Jensen
APS
5
Negative
Robert D
Arizona Public
1
Negative
Smith
Service Co.
Response: The bullets – o Interruptible Demand or Demand-Side Management and o Circumstances where … are not requirements that must be met, but
rather they define the conditions, either one or both, where Load is allowed to be interrupted. The SDT has rearranged the footnote to clarify the intent of the
footnote.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved through the appropriate re-dispatch of resources obligated to re-dispatch,

3

Balloter

Company

Segment

Vote

Comment

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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
John Tolo
Tucson Electric
1
Negative
The first sentence of the second paragraph appears to conflict with the first paragraph in that it
Power Co.
indicates that curtailment of transfers is allowed under certain conditions as long as it doesn‟t
result in the shedding of any firm Demand. Language needs to be added to the end of the first
sentence of the second paragraph of Footnote B that clarifies that the shedding of firm Demand as
clarified in paragraph one of Footnote B is allowed.
Scott Kinney
Avista Corp.
1
Affirmative
The first sentence of the second paragraph appears to conflict with the first paragraph in that it
indicates that curtailment of transfers is allowed under certain conditions as long as it doesn‟t
Robert
Avista Corp.
3
Affirmative
result in the shedding of any firm Demand. Language needs to be added to the end of the first
Lafferty
sentence of the second paragraph of Footnote B that clarifies that the shedding of firm Demand as
clarified in paragraph one of Footnote B is allowed.
Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.

William
Mitchell
Chamberlain

California Energy
Commission

9

Affirmative

I am voting for this improved standard but I am concerned that the first sentence of the second
paragraph appears to conflict with the first paragraph in that it indicates that curtailment of
transfers is allowed under certain conditions as long as it doesn‟t result in the shedding of any firm
Demand. This problem could be corrected by adding language to the end of the first sentence of
the second paragraph of Footnote B that clarifies that the shedding of firm Demand as clarified in
paragraph one of Footnote B is allowed.

4

Balloter

Company

Chang G Choi

1

Affirmative

5

Affirmative

James Tucker

City of Tacoma,
Department of
Public Utilities,
Light Division, dba
Tacoma Power
City of Tacoma,
Department of
Public Utilities,
Light Division, dba
Tacoma Power
Deseret Power

1

Affirmative

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Affirmative

James L.
Jones

Southwest
Transmission
Cooperative, Inc.

1

Affirmative

Travis
Metcalfe

Tacoma Public
Utilities

3

Affirmative

Max Emrick

Segment

Vote

Comment
Tacoma Power agrees that the revision is better than the existing language. However, to improve
clarity on the interrelationship of the 2 paragraphs of Footnote B, we strongly suggest adding the
following phrase to the end of the first sentence of the second paragraph, “unless the firm
Demand is allowed to be shed pursuant to the above paragraph in this footnote."

As drafted the first paragraph of proposed Footnote B identifies the objective of minimizing
interruption of Demand following Contingencies and goes on to identify the limited situation where
interruption of demand may be necessary. However, the first sentence of the second paragraph
appears to conflict with the first paragraph in that it indicates that curtailment of transfers is
allowed under certain conditions as long as it doesn‟t result in the shedding of any firm Demand.
Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed
PG&E supports the proposed footnote B. We believe, however, there is a potential for confusion
with the language as currently drafted. As drafted the first paragraph of proposed Footnote B
identifies the limited situations where interruption of demand may be necessary and would be
allowed. However, the first sentence of the second paragraph indicates that curtailment of
transfers is allowed under certain conditions as long as it doesn‟t result in the shedding of any firm
Demand. Taken together with the first paragraph, this requirement can be confusing because the
first paragraph potentially conflicts with the second paragraph. Please change the first sentence in
the second paragraph to read, "Curtailment of firm transfers is allowed, when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand, the interruption of which is otherwise allowed as described above.”
Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.
Tacoma Power agrees that the revision is better than the existing language. However, to improve
clarity on the interrelationship of the 2 paragraphs of Footnote B, we strongly suggest adding the
following phrase to the end of the first sentence of the second paragraph, “unless the firm
Demand is allowed to be shed pursuant to the above paragraph in this footnote.”

5

Balloter

Company

Segment

Vote

Comment

Keith
Morisette

Tacoma Public
Utilities

4

Affirmative

Michael C Hill

Tacoma Public
Utilities

6

Affirmative

Beth Young

Tampa Electric Co.

1

Affirmative

Ronald L
Donahey

Tampa Electric Co.

3

Affirmative

RJames
Rocha

Tampa Electric Co.

5

Affirmative

Benjamin F
Smith II

Tampa Electric Co.

6

Affirmative

Melissa Kurtz

U.S. Army Corps
of Engineers

5

Affirmative

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.

Brandy A
Dunn

Western Area
Power
Administration

1

Affirmative

As drafted, the first paragraph of proposed Footnote B identifies the objective of minimizing
interruption of Demand following Contingencies and goes on to identify the limited situation where
interruption of demand may be necessary. However, the first sentence of the second paragraph
appears to conflict with the first paragraph in that it indicates that curtailment of transfers is
allowed under certain conditions as long as it doesn‟t result in the shedding of any firm Demand.
Western recommends that the Drafting Team include language at the end of the first sentence of
the second paragraph of Footnote B that clarifies that the shedding of firm Demand as clarified in
paragraph one of Footnote B is allowed.

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed

Recommend adding language to paragraph 2, sentence 1 to clarify shedding of firm demand is
allowed as stated in Paragraph 1.

6

Balloter
Louise
McCarren

Company
Western Electricity
Coordinating
Council

Segment
10

Vote

Comment

Affirmative

WECC supports the concept that is clarified in the proposed language for Footnote B. We have
noted however, what could potentially be confusing language between paragraphs one and two of
the proposed language. Paragraph one correctly indicates that one of the objectives of
transmission planning is to minimize the likelihood and magnitude of interruption of Demand. The
first paragraph also recognizes that while this is an objective, there may be certain limited
conditions where Demand is interrupted. In recognizing this, the first paragraph lists those limited
instances when Demand may be interrupted. However, the first sentence of paragraph two could
be interpreted to mean that shedding of Firm Demand is not allowed. The sentence means that
shedding of Firm Demand is not allowed due to curtailment of firm transfers, but if there is a
situation where curtailment of firm transfers is necessary and curtailment of Demand per the
reasons listed in the first paragraph occurs, it should be clear that this is allowed. Suggest adding
the following language, or something similar, to the end of the first sentence of the second
paragraph of Footnote B. ...except as allowed above.
Response: The SDT has reorganized the footnote to clarify intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.

7

Balloter
Venkatarama
krishnan
Vinnakota

Company
BC Hydro

Segment
2

Vote
Negative

Comment
Footnote "b" of TPL-001/2/3/4 is still vague and not acceptable. The last paragraph of Footnote b
now reads: "Curtailment of firm transfers is allowed, when coupled with the appropriate redispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities remain
within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner‟s planning region are relied upon,
Facility Ratings in those regions would also be respected." We would like the SDT to answer the
following questions related to the paragraph quoted above:
1) What is meant by “firm transfers”? Is it simply energy flowing in real-time on Firm Transmission
Service (NERC defined term) that was not previously curtailed in the hour-ahead or day-ahead
scheduling processes, or does it refer to ALL Firm Transmission Service that was sold on a path?
2) Please provide an example of what an "appropriate re-dispatch of resources obligated to redispatch" could look like?
3) Assuming an outage of a single transmission line (N-1 Category B event) has occurred and
assuming that no "resources [are] obligated to redispatch" for this outage, would a transmission
provider be allowed to curtail Firm Transmission Service that it has sold in order to prepare to
withstand the next worst credible contingency?
4) Would transmission providers be allowed to sell Firm Transmission Service on a path above
what could be delivered with any one element of that path out of service across a range of
operating conditions?
5) If the proposed Footnote b is approved, and assuming an appropriate obligation to redispatch
could not be negotiated, would utilities have to reinforce their system (within 60 months) to ensure
that Firm Transmission Services already sold on particular paths would not be curtailed when any
one element of that path is out of service?
6) If a transmission provider employs Generation Dropping for single contingencies in order to
support Firm Transmission Service between regions, and assuming there are no provisions for
obligated re-dispatch, would the proposed Footnote b force a recalculation of firm vs non-firm
transfer capability?
7) Path 66 (PACI) and Path 65 (PDCI) can both see significant derates in their firm transfer
capability for single contingencies. How would the proposed Footnote b impact Firm Transmission
on these paths? Further, the Project 2010-11 SDT (Footnote “b”) should be amalgamated with the
Project No. 2006-02 SDT (TPL-001 through TPL004 amalgamation/update):
1. It doesn‟t make any sense to update Footnote “b” of TPL-001 based on the existing approved

8

Balloter

Company

Segment

Vote

Comment
version of TPL-001 when the language in that standard is being revised and terms that Footnote
“b” makes reference to will be changed. Draft #6 (2010-Oct-19) of TPL-001 has changed
“Footnote b” to “Footnote 9”.
2. Draft #6 of TPL-001 has changed the column heading relevant to “Footnote b” from “Loss of
Demand or Curtailed Firm Transfers” to “Interruption of Firm Transmission Service Allowed”.
3. Draft #6 of TPL-001 has seven new definitions including the following two definitions that would
be expected to be relevant to Footnote b: 3.1. Consequential Load Loss: All Load that is no longer
served by the Transmission system as a result of Transmission Facilities being removed from
service by a Protection System operation designed to isolate the fault. 3.2. Non-Consequential
Load Loss: Non-Interruptible Load loss that does not include: (1) Consequential Load Loss, (2) the
response of voltage sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.

4. The Project 2006-02 SDT has placed Draft #6 of TPL-001 on hold, stating, “The team will delay
moving the standard forward until the resolution of “footnote b” has become clear.”
Response: 1. For consistency with the existing standard text, the term „firm transfer‟ is retained. Therefore, the interpretation of “firm transfers” remains
unchanged.
2. One example would be a contractual arrangement that defines clear expectations to alternately serve Load upon the removal of the firm transfer so that no
loss of Load occurs.
3. In the planning timeframe, footnote „b‟ addresses single Contingencies (Cat. B) and footnote „c‟ addresses the Cat. C Contingencies. Neither footnote
prohibits System adjustments, which could include re-dispatch of your own resources to prepare for the next Contingency.
4. How Firm Transmission Service (FTS) is sold is addressed in individual tariffs in concert with the MOD standards.
5. The implementation plan provides 60 months after regulatory approval for entities to comply with the modified standard. How that is accomplished is up to
individual entities.
6. & 7 Each circumstance may need to be evaluated individually and additional documentation of understandings may be necessary.
7-1 - 4. Based on ballot comments and regulatory orders, the SDT determined that the best course of action was to address footnote „b‟ as a standalone item
and then incorporate the changes approved for footnote „b‟ into the new TPL-001-2 in a manner consistent with the other proposed changes in TPL-001-2.
Christopher L Consolidated
1
Negative
Interruptible Demand, like Demand-Side-Management, is an operational tool. We do not believe it
de
Edison Co. of New
appropriate to use operational tools for transmission planning. A load serving entity should not
Graffenried
York
claim to serve loads it plans to disconnect during a design contingency. In other words, these loads
should be excluded from the load forecast in the first place and, thereby, would not be represented
Peter T Yost
Consolidated
3
Negative
in power flows that are utilized to assess system performance under the TPL standards. This
Edison Co. of New
approach prevents the use of such load interruptions to address any deficiency found in TPL-type
York

9

Balloter

Company

Wilket (Jack)
Ng

Consolidated
Edison Co. of New
York

Segment
5

Vote
Negative

Comment
assessments.

Nickesha P
Carrol

Consolidated
6
Negative
Edison Co. of New
York
Response: Entities across the continent have many different Interruptible and Demand-Side Management programs that have many different attributes and
rules. Some entities have Interruptible Demand programs that are appropriate for planning purposes.
Chuck B
Manning

Electric Reliability
Council of Texas,
Inc.

2

Negative

The introductory paragraph of footnote b includes policy language. Since this is a reliability
standard-and not a policy directive-the general narrative setting forth the desired policy goal of
minimizing load-shedding is misplaced. Including policy language can cloud the specific issues the
standard attempts to address, and ERCOT recommends deleting the first two sentences in the
introductory paragraph.
The next sentence in the introductory paragraph goes on to state, generally, that demand may be
interrupted to "address BES performance requirements.” This phrase is vague. To which
performance requirements does this refer? The intent is not clear. If the intent is to generally
recognize the need to shed load to respect to NERC standards and to allow flexibility for an entity
to exercise discretion relative to meeting BES performance requirements, then that intent should
be clearly reflected in the language. Furthermore, the last sentence of the introductory paragraph
and the subsequent bullet points are arguably inconsistent with this approach, because they could
be viewed as removing an entity‟s flexibility/discretion by limiting the circumstances when load can
be shed.
The second bullet point is unnecessary, because it is already apparent that interruptible
demand/demand side management programs can be used according to their terms. This could
create confusion in that it could be implied that, absent the need to use these to meet BES
performance requirements, using them otherwise is inconsistent with/not allowed under footnote
b. Simply put, those products are not load shedding as contemplated by this footnote. Therefore
they should not be listed here.
With respect to the third bullet point, the phrase "demand that does not adversely impact overall
BES reliability" is not adequately defined, and provides opportunity for confusion. This is an
ambiguous phrase and can‟t be linked back to objective NERC standards/requirements. The bullet
points should avoid ambiguity to mitigate ambiguity risk in audits.

10

Balloter

Company

Segment

Vote

Comment
In addition, the last part of the language in this bullet imposing an open and transparent
stakeholder process is unclear. What is the intent behind requiring review in a stakeholder
process? If it is to establish the ability of the entity to develop load shedding procedures beyond
those explicitly contemplated in footnote b, ERCOT questions if it is reasonable for the responsible
entity to be required to get “permission” from stakeholders to implement reliability measures
related to its obligation as the functional entity. Again, the language simply is not clear.
Accordingly, ERCOT recommends this bullet point be removed. If it is retained, it should be revised
consistent with these comments to remove ambiguous language to mitigate potential confusion
around the meaning/scope of the footnote in the administration of the CMEP.
In addition, ERCOT recommends revising the draft footnote b to allow for planned Demand
interruption as a means of mitigation during interim periods when a unanticipated (such as
unexpected demand growth or unit retirements) or temporary change on the system occurs in a
timeframe that is shorter than the time necessary to plan and implement the system upgrades
necessary to avoid the Demand interruption.

Finally, in the last paragraph of footnote b, it isn‟t clear why “Transmission Service” was changed
to “transfers.” Firm transmission service is a service provided in some regions, and it provides
relative value to other types of services-e.g., non-firm and network. The mention of transmission
service may also be irrelevant in this footnote, since the allowance of its interruption doesn't also
allow for load shedding. Therefore, ERCOT recommends eliminating the last paragraph of footnote
b.
Response: The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to provide
a balance between flexibility and consistency across NERC. No change made.
The term “BES performance requirements” references the other requirements within the TPL standard and the SDT has removed the phrase “demand that does
not adversely impact overall BES reliability”.
In a previous posting, entities had stated that it was not clear that the use of Interruptible Load and Demand Side Management was permitted. The SDT added
this section to address those concerns. The SDT has reorganized and reformatted the footnote to improve clarity.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm

11

Balloter

Company

Segment

Vote

Comment

Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
The open and transparent process does not require “permission”, but rather it facilitates the open sharing of information between entities that have
responsibility for ensuring BES reliability.
The SDT decided to not limit the use of the footnote to a specific time period because there are circumstances where the longer term use may be implemented
without adversely impacting BES reliability.
For consistency with the existing standard text, the term „firm transfer‟ is retained. No change made.
Claudiu
GDS Associates,
1
Negative
We appreciate all the work conducted by SDT to adjust current footnote “b” however, we disagree
Cadar
Inc.
with the current approach mainly from the same reasons iterated during last comment period, as
follows:
• The definition does not go far enough with recognition that interruption of Demand should be
mitigated if at all possible. The language should encourage the TP to develop mitigation plans that
could be implemented as an alternative to Demand interruption.
• Use of Interruptible Demand should only be implemented if the Transmission Planner can point
to a contract between the Transmission Provider and Transmission Customer that permits load
curtailment.
• Under FERC Order 890, Conditional Firm transmission service can be granted for entities who
voluntarily acknowledge the right of the Transmission Provider to curtail their transaction or
provide re-dispatch. This should be the only transfer which can be utilized in the Planning Horizon
for interruption of Demand for Note b.
We suggest using the following wording as emphasized below: “An objective of the planning
process should be to minimize the likelihood and magnitude of interruption of Demand following
Contingency events and to develop mitigation plans that do not call for the curtailment of Demand.

12

Balloter

Company

Segment

Vote

Comment

It is recognized that Demand will be interrupted if it is directly served by the elements removed
from service as a result of the Contingency and in very limited circumstances when approaching
intermediate solutions to restore BES reliability. When interruption of Demand is utilized within the
planning process, such interruption is limited to:
? Demand that is directly served by the elements that are removed from service as a result of the
Contingency,
? Interruptible Demand or Demand-Side Management, where the Customer has given explicit
rights to the Transmission Provider for curtailment of their Demand,
? Demand, other than Interruptible Demand or Demand-Side Management, that does not
adversely impact overall BES reliability where the circumstances describing the use of such
Demand are documented, including alternatives evaluated; where the Load-Serving Entity who has
responsibility for serving such Demand has agreed to the curtailment, and where the application is
subject to review and acceptance in an open and transparent stakeholder process. Curtailment of
Firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch per the terms and conditions of the confirmed transmission service request between
the Transmission Customer and Transmission Provider, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand. Where Facilities external to the Transmission Planner‟s planning
region are relied upon, Facility Ratings in those regions would also be respected. In addition, any
Conditional Firm transfers may be curtailed, in accordance with the terms and conditions of the
confirmed transmission service request between the Transmission Customer and Transmission
Provider.”
Response: In the footnote, the SDT has acknowledged that interrupting Firm Demand is not the preferred solution to BES concerns, while recognizing that this
may not always be possible. The SDT believes that the footnote as drafted strikes an appropriate balance. No change made.
It is well understood that there must be some agreement or contract before interruptible Demand or Demand-Side Management can be utilized by the planner.
The SDT disagrees that there should be a prohibition on utilizing other resources obligated to re-dispatch for Contingencies, unless it has been characterized as
“conditional firm”. Entities should not be restricted from utilizing other dispatch scenarios, as long as Firm Demand is not interrupted.
For the reasons stated above, the SDT has not modified the footnote as suggested.
Joe D Petaski Manitoba Hydro
1
Negative
The last bullet should be made clearer by adding the words “in jurisdictions” before the word
“where”. Not all jurisdictions are mandated to have a stakeholder process, so the standard should
Greg C.
Manitoba Hydro
3
Negative
be clearly written to recognize this situation. “Circumstances where the use of Demand interruption
Parent
are documented, including alternatives evaluated; and IN JURISDICTIONS where the Demand
S N Fernando Manitoba Hydro
5
Negative
interruption is subject to review in an open and transparent stakeholder process that includes
addressing stakeholder comments.”
Daniel
Manitoba Hydro
6
Negative

13

Balloter

Company

Segment

Vote

Comment

Prowse
Response: The SDT believes that if Firm Demand is planned to be interrupted utilizing footnote „b‟, there must be an open and transparent stakeholder
process to ensure that all parties that may be impacted have been notified and have an opportunity to provide comments. No change made.
Spencer
Tacke

Modesto Irrigation
District

4

Negative

I am voting NO on the proposed revision because the second bullet of the proposed revision is
nebulous as to how the exemption process will occur, and how it will be monitored by the auditors.

Also, the last sentence of the last paragraph of the proposed change is nebulous about keeping
facility flows within applicable Normal and Emergency thermal ratings. Thank you.
Response: Rather than mandate a one-size-fits-all process, the SDT has provided entities the latitude to utilize existing processes, modify existing processes,
or create new processes to provide an open and transparent stakeholder process. The SDT cannot comment on future actions of the auditors.
The SDT disagrees that maintaining Facilities within applicable Facility Ratings is a nebulous concept. That part of the footnote was included to ensure that the
plans to resolve a situation on a planner‟s System did not create other overloads. No change made.
Saurabh
National Grid
1
Negative
National Grid supports the direction the drafting team has taken. However, it has a few concerns
Saksena
with the language of the footnote as amended.
1. Use of the term “Demand”: In the first sentence, it is unclear whether the term Demand
includes Interruptible Demand and Demand-Side Management. It is suggested that interruption of
Demand be clarified to exclude Interruptible Demand or Demand-Side Management.
2. It is unclear whether the second bullet includes Demand which is interrupted by the elements
removed from service. Clarification should be made such that Demand which is interrupted by the
elements removed from service should not be included in this bullet.

14

Balloter
Michael
Schiavone

Company
Niagara Mohawk
(National Grid
Company)

Segment
3

Vote
Negative

Comment
3. National Grid also suggests changing “Demand interruption” to “interruption of Demand” in
second bullet under “b)” to avoid awkward and incorrect phasing.
4. „Addressing stakeholder comments‟ introduces undefined actions which may be required in
response to the comments. If „Demand interruption is subject to review in an open and transparent
stakeholder process‟, then stakeholder comments will be addressed without creating an undefined
commitment to require it. As a result, “that includes addressing stakeholder comments” should be
deleted.
5. The second paragraph seems to be restricting the use of Demand interruption for the sake of
Firm Transfer reduction. This can be stated directly without adding the confusion of re-dispatch. By
coupling re-dispatch with a constraint of not shedding Demand, the paragraph also creates
confusion as to what to do in a situation where the amount of Demand that is allowed to be shed
in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be allowed?
National Grid suggests that the paragraph be rewritten as follows: „Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can
be demonstrated it does not result in the interruption of any Demand (other than Interruptible
Demand or Demand Side Management).‟
6. National Grid seeks clarification if there is an intended distinction between the use of the term
“firm Demand” and the defined term “Firm Demand” or is that just a typo?

7. The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to
cause reliability concerns in another area while addressing your own. This same thought would
have to be added to multiple NERC standards if it were added here, otherwise it would infer that
such actions are acceptable in all other standards.
Response: 1. The SDT has reorganized the text in the footnote to address this concern.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:

15

Balloter

Company

Segment

Vote

Comment

Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
2. The SDT has reorganized the text in the footnote to address this concern.
3. The SDT believes that the proposed change does not add additional clarity to the footnote. No change made.
4. The SDT disagrees that each review process automatically will have a response to comments element. Therefore, the SDT added that element to ensure
that all stakeholder processes will include that element. No change made.
5. The SDT has reorganized the text in the footnote to address this concern.
6. The SDT has corrected the capitalization errors.
7. Since the planned action of curtailing of firm transfers may adversely impact neighboring systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. The SDT disagrees that an explicit statement in this footnote changes the intent of all other standards. No
change made.
Tony
Nebraska Public
3
Negative
NPPD votes NO due to the ambiguity of the terms “Curtailment of firm transfers is allowed, when
Eddleman
Power District
coupled the appropriate re-dispatch of resources” with respect to a Category B contingency event.
NPPD does not support the curtailment of firm transfers or re-dispatch to meet the performance
Don Schmit
Nebraska Public
5
Negative
requirements during a Category B (N-1) event. Curtailment of firm transfers and re-dispatch are
Power District
allowable following acceptable performance for the Category B (N-1) event, to get ready for the
next Category C type of event.
Response: As drafted, footnote „b‟ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language
recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be
utilized for a limited time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the
Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not
obligated to re-dispatch, the firm transfers cannot be curtailed. No change made.

16

Balloter

Company

Randy
MacDonald

New Brunswick
Power
Transmission
Corporation

Segment
1

Vote
Negative

Comment
In general: NERC standards should not dictate circumstances or acceptable transmission
contingencies under which the tripping of customers loads is acceptable. That should be an issue
between the utility of supply, the customer, and the local regulating body so long as the
interruption to customers (for whatever contingency) is controlled and does not cause problems on
the BES, or to neighboring utilities.
Specifically, 1. The second bullet: The last sentence (following the semicolon) should be removed.
The local regulating body should provide input or approval.

2. NB Power Transmission interprets that the currently proposed footnote allows for the two
bulleted options to be used exclusively or in combination. Thus for clarification suggest adding “or”
after the first bulleted item.
Response: The SDT disagrees that this should be handled exclusively with the local regulating body. The SDT believes that in situations where an entity‟s
planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the entity needs to share those plans in an open and
transparent stakeholder process to ensure that other parties that may be adversely impacted by those decisions have the ability to review those plans. No
change made.
The SDT has reorganized the footnote to clarify its intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.

17

Balloter
Alden Briggs

Company
New Brunswick
System Operator

Segment
2

Vote
Negative

Comment
NBSO agrees with the principles of the current version of the proposed footnote assuming NBSO‟s
interpretation of the footnote is correct. NBSO has the following detailed comments: 1. The first
paragraph contains many general statements that attempts to capture essential planning
principles. NBSO feels that such language is not suited for a footnote. NBSO suggests re-wording
of the first paragraph to state: Interruption of Demand may be utilized within the planning process
to address BES performance requirements. Such cases are limited to:
NBSO also suggests turning the phrase that addresses Demand lost that was served by elements
removed from service as a result of a Contingency into a bullet item. NBSO feels that this adds
clarity since all of the acceptable instances of Demand interruption are now listed as bulleted
items.
2. NBSO interprets that the currently proposed footnote allows for the two bulleted options to be
used exclusively or in combination. Thus for clarification NBSO suggests adding “or” after each
bulleted item, with the exclusion of the final bulleted item.
3. NBSO suggests removing the last sentence of the last paragraph. Likely all industry members
understand that causing reliability concerns in other areas is never acceptable. This principle is not
limited to the standard in question, and thus such a statement could require the update of other
standards.
4. NBSO interprets that the use of the word “Demand” in the second bullet of the proposed
footnote is referring to use of Firm Demand since the first bullet covers the other types of Demand
(Demand = Firm Demand + Interruptible Demand). As such NBSO suggests replacing “Demand”
with “Firm Demand” in the second bullet.
5. NBSO feels that the statement “that includes addressing stakeholder comments” should be
removed from the last phrase of the second bullet. An open and transparent stakeholder process
should adequately address stakeholder comments and concerns. Explicitly specifying that all
stakeholder comments be addressed may add undue burden if the word “address” is misconstrued.
The task of addressing stakeholder comments is more appropriately addressed and defined in each
area‟s respective process.
6. NBSO suggests replacing the word “shedding” with “interruption” in the last phrase of the last
paragraph to remain consistent with the rest of the proposed footnote. NBSO also suggests
capitalizing “firm” in the term “Firm Demand” to remain consistent with the NERC glossary of
terms.

18

Balloter

Company

Segment

Vote

Comment
7. There is no term “transfers” in the NERC glossary of terms. Perhaps some other defined term
from the glossary could be used in lieu of “transfers” (e.g. Firm Transmission Service).

Taking into account the NBSO comments, the footnote could read as follows: b) Interruption of
Demand may be utilized within the planning process to address BES performance requirements.
Such cases are limited to: -Demand directly served by Elements removed from service as a result
of a Contingency, or -Use of Interruptible Demand or Demand-Side Management, or -Interruption
of Firm Demand when acceptable circumstances for such interruptions are documented (including
alternatives evaluated), and where the Firm Demand interruption is subject to review in an open
and transparent stakeholder process. Curtailment of Firm Transmission Service is allowed when
coupled with the appropriate re-dispatch of resources obligated to do so, and it can be
demonstrated that Facilities remain within applicable Facility Ratings and there is no additional
interruption of Firm Demand.
Response: 1 & 2. The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to
provide a balance between flexibility and consistency across NERC. The SDT has reorganized the footnote to clarify its intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
3. Since the planned action of curtailing of firm transfers may adversely impact neighboring Systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. The SDT disagrees that an explicit statement in this footnote changes the intent of all other standards.
4. The SDT has reorganized the footnote to clarify its intent and address the issue raised.
5. The SDT believes that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the

19

Balloter

Company

Segment

Vote

Comment

entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those
decisions have the ability to review those plans. No change made.
6. The SDT does not believe that replacing the term shedding with interruption adds clarity and did not make the proposed change. The SDT has reorganized
the footnote to clarify its intent and address the second issue.
7. For consistency with the existing standard text, the term „firm transfer‟ is retained. No change made.
David H.
Northeast Utilities
1
Negative
The revised language of Footnote b suggests that non-consequential demand interruption (load
Boguslawski
that is not directly served by the elements removed from service as a result of the contingency)
could be used to mitigate reliability concerns arising from NERC Category B contingency events
(i.e., single element contingencies). This language seems to encourage operational workarounds
and adds burdens for operators of the system. NU believes this is not consistent with planning a
highly reliable bulk electric system and thus does not support this weaker language.
Response: The SDT believes that the language in this footnote is not weaker and does not encourage operational workarounds. The footnote language
provides the framework necessary to ensure that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES
Facility Ratings that the entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely
impacted by those decisions have the ability to review those plans. No change made.
Brad Chase
Orlando Utilities
1
Negative
“Two Items prevent us from voting yes. Item #1: The standard team should clarify if the bullets
Commission
under note B are intended to be an AND (both conditions met) or an OR (either condition met). As
currently written it is not clear.
Ballard Keith
Orlando Utilities
3
Negative
Mutters
Commission
Item #2: The section under firm transfers is in conflict with the section above. If Demand is being
curtailed under the first or second bullet and it‟s served by firm service then service should also be
curtailed, however as written any demand served by firm service could not be curtailed. Other then
these items the revisions does an excellent job of addressing the issue of load shedding under first
contingency conditions and practical reliablity.”
Response: The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management

20

Balloter

Company

Segment

Vote

Comment

Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Linda Brown

San Diego Gas &
Electric

1

Negative

Footnote b is a group of exceptions to the requirements for Category B contingencies. To add
clarity to the footnote, SDG&E would prefer that each exception be listed separately within the
footnote. As SDG&E understands the footnote, the following exceptions can occur after the loss of
a single element,
• Interruptible Demand can be used to unload a circuit, but the circuit(s) must remain below
emergency rating(s) at all times.
• Demand-Side Management can be used to unload a circuit, but the circuit(s) must remain below
emergency rating(s) at all times.
• Demand served by a radial element which is faulted may be interrupted.
• Curtailment of firm transfers is allowed, when coupled with re-dispatch of resources obligated to
re-dispatch.
SDG&E votes against the proposed language for the following reasons: SDG&E feels system
reliability alone should drive the need for a technical standard and the language of the standard
should reflect the need without reference to the process. FERC Order 890 set the forum for the
stakeholder process which provides commercial incentives and a level playing field for any
participant to build a transmission project. When considering compliance to the standards,
reference to “stakeholder process” is inappropriate and should be removed. Section 4 of the TPL
standards assigns responsibility for meeting the standards to the Planning Authority and the
Transmission Planner. These entities are subject to penalties if the requirement is not met. Use of
“stakeholder process” in the requirement implies that entities other than the Planning Authority or
the Transmission Planner have authority over how the standards are to be met without any
financial risk. If the “stakeholder process” language is not removed, SDG&E feels stakeholders
involved in the process should be registered with NERC and subject to the same audit
requirements and penalties as the Planning Authority or the Transmission Planner. Furthermore,
the California Transmission Owners have a FERC approved stakeholder process that is
administered by the California ISO. Addition of the term “stakeholder process” in a standard may
have unintended consequences.

21

Balloter

Company

Segment

Vote

Comment

Response: While the SDT believes that SDG&E proposed bullet list is consistent with the footnote as drafted, the list is not as inclusive as the footnote.
Therefore, the SDT has retained the existing text and reorganized the footnote for clarity.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
The SDT believes that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the
entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those
decisions have the ability to review those plans. No change made.
Charles H
Southwest Power
2
Negative
The second paragraph of the footnote seems to be restricting the use of Demand interruption for
Yeung
Pool
the sake of Firm Transfer reduction. This can be stated directly without adding the confusion of redispatch. By coupling re-dispatch with a constraint of not shedding Demand, the paragraph also
creates confusion as to what to do in a situation where the amount of Demand that is allowed to
be shed in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be
allowed? We suggest that the paragraph be rewritten as follows: “Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can
be demonstrated it does not result in the interruption of any Demand (other than Interruptible
Demand or Demand Side Management).”
Response: The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved through the appropriate re-dispatch of resources obligated to re-dispatch,

22

Balloter

Company

Segment

Vote

Comment

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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Larry Akens
Tennessee Valley
1
Negative
TVA appreciates the SDT‟s efforts to clarify and improve this complex and challenging area.
Authority
However, as mentioned in our last comments regarding footnote b, TVA still believes that the
SDT‟s proposal is still focusing more on reliability of local loads than on the overall reliability of the
Ian S Grant
Tennessee Valley
3
Negative
BES. Reliability of local loads should be addressed outside the TPL standards and therefore should
Authority
not be used/referenced in footnote b. Existing stakeholder processes (referred to in the SDT
George T.
Tennessee Valley
5
Negative
proposal) typically focus on larger system issues and not on local load serving. TVA believes that
Ballew
Authority
some local load should be allowed to be dropped in order to maintain BES reliability. Instead of the
proposed footnote b, TVA suggests that the SDT define a “local area” with guidelines detailing the
Marjorie S.
Tennessee Valley
6
Negative
reliability requirements for these local area loads. This would separate the local area load
Parsons
Authority
requirements from the BES requirements in the TPL standards.
Response: The original footnote „b‟ focused on local area and limited interruption of Demand. Since individual entities planning philosophies are different
across North America, the SDT has been unable to determine a one-size-fits-all definition for local area. Therefore, the SDT adopted an approach that allows
entities to utilize input from stakeholders in an open and transparent process. In this way, any affected party has a mechanism to ensure that the planners are
planning a reliable BES. No change made.
Pat G.
BC Hydro and
3
Negative
Harrington
Power Authority
Gordon
BC Transmission
1
Negative
Rawlings
Corporation
Response: With no comment provided, the SDT is unable to provide a response.
Gregg R
Griffin

City of Green Cove
Springs

3

Affirmative

An objective of the planning process should be to minimize the likelihood and magnitude of
interruption of Demand following Contingency events. However, it is recognized that Demand will

23

Balloter

Company

Segment

Vote

Comment
be interrupted if it is directly served by the Elements removed from service as a result of the
Contingency. Furthermore, in limited circumstances Demand may need to be interrupted to
address BES performance requirements. When interruption of Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management Circumstances where the uses of Demand
interruption are documented, including alternatives evaluated; and where the Demand interruption
is subject to review in an open and transparent stakeholder process that includes addressing
stakeholder comments. Curtailment of firm transfers is allowed, when coupled with the appropriate
re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any
firm Demand. Where Facilities external to the Transmission Planner‟s planning region are relied
upon, Facility Ratings in those regions would also be respected.

Response: Thank you for your support.
Guy V. Zito

Northeast Power
Coordinating
Council, Inc.

10

Affirmative

1. There is concern with the use of the term Demand. It is unclear throughout the footnote
whether or not the term Demand includes Interruptible Demand or Demand-Side
Management. It is suggested that interruption of Demand be clarified to not include
Interruptible Demand or Demand-Side Management to more clearly show the permitted
use of Load shedding.
2. It is unclear whether the second bullet includes Demand which is interrupted by the
elements removed from service. Clarification should be made such that Demand which is
interrupted by the elements removed from service should not be included in this bullet.
3. Language that mitigation of Load and/or Demand interruption should be pursued within
the planning process should be reinstated as reinforcement of a Transmission Providers‟
planning obligations to their load customers, and system operations.
4. Footnote „b‟ should be made to read as follows: b) An objective of the planning process is
to minimize the likelihood and magnitude of interruption of Load and/or Demand following
Contingency events. Interruption of Load and/or Demand is discouraged and all measures
to mitigate such interruption should be pursued within the planning process. However, it is
recognized that Load and/or Demand will be interrupted if it is directly served by the
elements automatically removed from service by the Protection System as a result of a
Contingency. Furthermore, in extraordinary circumstances within the planning process
Load and/or Demand may need to be interrupted to address BES performance
requirements. When interruption of Load and/or Demand is utilized within the planning

24

Balloter

Company

Segment

Vote

Comment
process to address BES performance requirements, such interruption is limited to:
• Circumstances where the use of Load and/or Demand interruption are documented,
including alternatives evaluated; and where the Load and/or Demand interruption is made
available for review in an open and transparent stakeholder process. If Load and/or
Demand interruption is necessary, planning should indicate the amount needed, and not
specify how it would be obtained. What Load and/or Demand is interrupted is an
operational decision.
5. Additional comments not included in the material listed for footnote „b‟ on the Comment
Form. In the paragraph below the bullets in footnote „b‟, confusion is introduced through
the use of the term “firm Demand”. It is unclear how this is different than the defined term
“Firm Demand” and what the implications of the term “firm Demand” are. This footnote
should not discourage such adjustments which actually increase the reliability of service to
end users.

6. The last sentence of footnote „b‟ is unnecessary and should be deleted. It is never
acceptable to cause reliability concerns in another area while addressing your own.
Response: 1. The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
2. The SDT has reorganized the footnote to clarify its intent and address the issue raised.

25

Balloter

Company

Segment

Vote

Comment

3. & 4. The SDT addressed these concerns by including the phrase “including alternatives evaluated” and does not believe that it is appropriate to dictate that
the planners must evaluate “all measures to mitigate” annually or the specific details concerning documentation of alternatives.
5. The SDT has corrected the capitalization errors.
6. Since the planned action of curtailing of firm transfers may adversely impact neighboring systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. No change made.
Ajay Garg
Hydro One
1
Affirmative
Hydro One is casting an affirmative vote on the revisions to Table 1, footnote „b‟ in TPL-001-1,
Networks, Inc.
TPL-002-1b, TPL-003-1a, and TPL-004-1. However, we believe the proposed language might be
confusing and should be modified to read as follows: “b) It is recognized that Demand will be
David L
Hydro One
3
Affirmative
interrupted if it is directly served by the Elements removed from service as a result of the
Kiguel
Networks, Inc.
Contingency. When interruption of Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to: o Interruptible Demand or Demand-Side
Management o Circumstances where the uses of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments. Curtailment of
firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings
and the re-dispatch does not result in the interruption of any firm Demand. Where Facilities
external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those
regions would also be respected.” Note that the voting system does not permit to enter re-lined
comments. We can provide a red-lined document with our proposal upon request.
Response: The SDT believes that the sentences deleted in your proposed footnote are necessary to provide context for the items that follow and has crafted
the language to provide a balance between flexibility and consistency across NERC. The SDT has reorganized the footnote to clarify its intent.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.

26

Balloter

Company

Segment

Vote

Comment

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Henry ErnstDuke Energy
3
Affirmative
The effective date in the Implementation Plan needs to be changed to match the Effective Date in
Jr
Carolina
the standards, in order to clarify the allowed interruption of Non-consequential load before the new
Footnote 'b' takes effect.
Response: The effective dates in the Implementation Plan match those in the standards. No change made.
Mark B
Thompson

Alberta Electric
System Operator

2

Abstain

While the AESO does not generally disagree with the intent of the proposed change, we have
voted "abstain". In particular, as reflected in the adopted Alberta Reliability Standard TPL-002-AB0, no loss of Demand and Generation have been given equal consideration for Category B
contingencies. In addition, within the Alberta energy market structure and the operation of the
transmission system, there are no firm transfers on transmission facilities in Alberta.
Response: Individual jurisdictions are allowed to have more restrictive standards and therefore, this revision to the standard does not dictate that a jurisdiction
must change its requirements. The SDT recognizes that there may be areas or markets that do not utilize terms contained within the standard.

27

Consideration of Comments
TPL Table 1 Order – Project 2010-11

The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on the revision
of TPL-002 footnote ‘b’ and TPL-001 footnote 12. These standards were posted for a 30-day public
comment period from July 31, 2012 through August 29, 2012. Stakeholders were asked to provide
feedback on the standards and associated documents through a special electronic comment form.
There were 51 sets of comments, including comments from approximately 117 different people from
approximately 81 companies representing 9 of the 10 Industry Segments as shown in the table on the
following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
Due to comments received, the SDT has made the following changes to the text:
•
•

•

•

Effective date – updated to latest approved language
Main footnote
o Grammatical change from ‘should be’ the intent to ‘is’ the intent.
o Clarified the near-term and long-term requirements.
o Defined the ceiling threshold as 75 MW.
Attachment 1
o Section I
 Clarified that an existing process can be utilized, as long as it meets the criterion
in Section I.
 Changed ‘all affected stakeholders’ to ‘affected stakeholders’.
 Changed ‘specific applications’ to ‘specific locations’.
 Added statement that says that the process does not have to be repeated in
subsequent years if conditions haven’t changed.
o Section II
 Item 2.b has been clarified to better show the SDT’s intent.
 Item 8 has been changed from ‘planners’ to ‘Transmission Planners and Planning
Coordinators and clarified to indicate that it includes both the local and adjacent
entities.
o Section III
 Clarified role of regulatory authority.
 Deleted role of Regional Entity.
 Defined the ceiling threshold as 75 MW.
Footnote 12 only – Corrected terminology to use ‘Non-Consequential Load loss’ instead of ‘Firm
Demand interruption’.

The SDT is requesting that this project be moved forward to the initial ballot and comment phase of the
process.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

2

Index to Questions, Comments, and Responses

1.

Do you agree with the description and components of the the Stakeholder Process in the body of
the footnote including the maximum capacity threshold (currently shown as ‘x’ MW but the SDT
will fill in the value after the data request is complete and will submit the value for industry
comment and approval in the next posting)? If you do not support these changes or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. For the maximum capacity item, please supply any technical
rationale for your comment along with limiting conditions and any current criteria in use at your
entity........................................................................................................................ 11

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of
Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 33

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II
of Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 53

4.

Do you agree with the Instances for which Approval of Interruptions is required in Section III of
Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 72

5.

If you have any other comments on this Standard that you haven’t already mentioned above,
please provide them here. ............................................................................................ 98

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Sunitha Kothapalli

Additional Member

Puget Sound Energy
WECC 1, 3, 5

2. Peter (Pete) M Jones

Transmission Contracts

WECC 1, 3, 5

3. Kebede Jimma

Transmission Planning

WECC 1, 3, 5

4. Gary Shumate

Transmission Planning

WECC 1, 3, 5

5. Harris Wayne

Transmission Planning

WECC 1, 3, 5

6. Carol Jaeger

Transmission Planning

WECC 1, 3, 5

7. Zachery (Zach) Sanford

Transmission Planning

WECC 1, 3, 5

8. Eleanor Ewry

Transmission Planning

WECC 1, 3, 5

Group

3

X

4

5

6

7

8

9

10

X

Additional Organization Region Segment Selection

1. Joseph (Joe) W Seabrook Transmission Contracts

2.

X

2

Guy Zito

Northeast Power Coordinating Council

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Carmen Agavriloai

Independent Electricity System Operator

NPCC 2

3.

Greg Campoli

New York Independent System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8.

Kathleen Goodman

ISO - New England

NPCC 2

9.

Michael Jones

National Grid

NPCC 1

Hydro One Networks Inc.

NPCC 1

11. Michael R. Lombardi Northeast Utilities

NPCC 1

12. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

13. Bruce Metruck

New York Power Authority

NPCC 6

14. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Brian Robinson

Utility Services

NPCC 8

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

24. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

3.

Group

Jonathan Hayes

Additional Member

Additional Organization

Southwest Power Pool Reliability Standards
Development Team

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

City Utilities of Springfield

SPP

1, 4

Westar Energy

SPP

1, 3, 5, 6

4. Tiffany Lake

4

5

6

7

X

X

X

X

X

Region Segment Selection

1. Jonathan Hayes
John Allen

3

Region Segment Selection

1.

10. David Kiguel

2

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5. Harold Wyble

Kansas City Power and Light Company SPP

1, 3, 5, 6

6. Katy Onnen

Kansas City Power and Light Company SPP

1, 3, 5, 6

7. Don Taylor

Westar

1, 3, 5, 6

4.

Group

SPP

Bob Steiger

Salt River Project

2

X

3

4

X

5

6

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Brian Keel

5.

SRP

Group

WECC 1

WILL SMITH

MRO NSRF

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

MRO

1, 3, 5, 6

2.

CHUCK LAWRENCE ATC

OPPD

MRO

1

3.

TOM BREENE

WPS

MRO

3, 4, 5, 6

4.

JODI JENSON

WAPA

MRO

1, 6

5.

KEN GOLDSMITH

ALT

MRO

4

6.

ALICE IRELAND

XCEL

MRO

1, 3, 5, 6

7.

DAVE RUDOLPH

BEPC

MRO

1, 3, 5, 6

8.

ERIC RUSKAMP

LES

MRO

1, 3, 5, 6

9.

JOE DEPOORTER

MGE

MRO

3, 4, 5, 6

10. SCOTT NICKELS

RPU

MRO

4

11. TERRY HARBOUR

MEC

MRO

5, 6, 1, 3

12. MARIE KNOX

MISO

MRO

2

13. LEE KITTELSON

OTP

MRO

1, 3, 4, 5

14. SCOTT BOS

MPW

MRO

1, 3, 5, 6

15. TONY EDDLEMAN

NPPD

MRO

1, 3, 5

16. MIKE BRYTOWSKI

GRE

MRO

1, 3, 5, 6

17. DAN INMAN

MPC

MRO

1, 3, 5, 6

6.

Group

Jim Kelley

Additional Member

Additional Organization

SERC EC Planning Standards Subcommittee

X

X

Region Segment Selection

1. John Sullivan

Ameren

SERC

1

2. Bob Jones

Southern Company Services SERC

1

3. Pat Huntley

SERC

SERC

NA

4. Darrin Church

TVA

SERC

1

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

7.

Group

Additional Organization
East Kentucky Power Cooperative

SERC

1, 3, 5

2. Noman Williams

Sunflower Electric Power Corporation

SPP

1

3. David Albers

Brazos Electric Power Cooperative, Inc. ERCOT 1, 5

Group

Chris Higgins

4

5

6

7

8

9

X

Region Segment Selection

1. Ashley Gonyer

8.

3

ACES Power Member Standards
Collaborators

Jason Marshall

Additional Member

2

Bonneville Power Administration

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Chuck

Matthews

WECC 1

2. Allen

Chan

WECC 1, 3, 5, 6

Individual
10. Individual

Tim Ponseti, VP
Antonio Grayson

TVA Transmission Reliability Engineering &
Controls
Southern Company

X

X

X

X

11.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

12.

Individual

Brandy A. Dunn

Western Area Power Administration

X

13.

Individual

Aaron Staley

Orlando Utilities Commission

X

14.

Individual

Chifong Thomas

BrightSource Energy, Inc.

15.

Individual

Jose H Escamilla

CPS Energy

16.

Individual

Mark Westendorf

MISO

17.

Individual

Jennifer Wright

San Diego Gas & Electric

18.

Individual

Patrick Brown

Essential Power, LLC

19.

Individual

Keith Morisette

X

X

X

X

X

X

X

X

X

9.

X
X

X

X

X

X

X

X
X

X
X

X

X

Individual

John Burnett

Tacoma Power
Los Angrles Department of Water and
Power

21.

Individual

Nazra Gladu

Manitoba Hydro

22.

Individual

Michael Falvo

Independent Electricity System Operator

23.

Individual

Kirit Shah

Ameren

X

X

X

X

24.

Individual

Thad Ness

American Electric Power

X

X

X

X

20.

X

X

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

7

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

25.

Individual

John Delucca

LCEC (Lee County Electric Cooperative

X

26.

Individual

Andrew Z. Pusztai

X
X

X

X

X

X

X

X

X

X

X

X

Individual
28. Individual

James Tucker
Brian Keel

29.

Individual

Andrew Gallo

City of Austin dba Austin Energy

30.

Individual

Anthony Jablonski

ReliabilityFirst

31.

Individual

Kayleigh Wilkerson

Lincoln Electric System

X

X

32.

Individual

Milorad Papic

Idaho Power Co.

X

X

33.

Individual

Martyn Turner`

X

Individual

Jonathan Fidrych

Individual

John Martinsen

LCRA Transmission Services Corporation
Tri-State Generation & Transmission
Association, Inc.
Public Utility District No. 1 of Snohomish
County

36.

Individual

Robert W. Creighton

Nova Scotia Power

X

37.

Individual

Greg Rowland

Duke Energy

X

38.

Individual

Chris de Graffenried

Consolidate Edison Co. of NY, Inc.

39.

Individual

Charlie Pottey

Sierra Pacific Power Co d/b/a NV Energy

40.

Individual

Richard Vine

California Independent System Operator

41.

Individual

charlie pottey

nevada power company dba nvenergy

X

42.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

43.

Individual

Chris Scanlon

Exelon

Individual
45. Individual

Catherine Mathews
Robert Casey

NorthWestern Energy (NWMT)
Georgia Transmission Corporation

46.

Kathleen Goodman
Bangalore
Vijayraghavan

ISO New England Inc.

34.
35.

44.

47.

Individual
Individual

8

9

10

X

American Transmission Company
Deseret Generation & Transmission
Cooperative
Salt River Project

27.

7

X

X

X

X

X

X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

PG&E Company

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

8

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

48.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

Individual
50. Individual

Steve Myers
Ed O'Brien

Electric Reliability Council of Texas, Inc.
Modesto Irrigation Districtt

51.

R. Peter Mackin

Utility System Efficiencies, Inc.

49.

Individual

2

X

3

4

X

5

X

6

7

8

X

X
X

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

X

X
X

9

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: Thank you for following the new method of commenting that helps to avoid needless duplication of effort for
the SDT. Your company name will be included in the participant list and the comments in full will be reviewed by the drafting team
members under the Salt River Project comment/response.
Organization

Yes or No

Support Comments Submitted by Another Entity

Puget Sound Energy

Agree

Salt River Project

Sierra Pacific Power Co d/b/a NV Energy

Agree

WECC

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

10

1. Do you agree with the description and components of the Stakeholder Process in the body of the footnote including the
maximum capacity threshold (currently shown as ‘x’ MW but the SDT will fill in the value after the data request is complete and
will submit the value for industry comment and approval in the next posting)? If you do not support these changes or you agree
in general but feel that alternative language would be more appropriate, please provide specific suggestions in your comments.
For the maximum capacity item, please supply any technical rationale for your comment along with limiting conditions and any
current criteria in use at your entity.

Summary Consideration: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the
concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a stakeholder process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Several commenters suggested that there should be no limitation on the amount of Load that could be shed under footnote ‘b’. The
SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed out the
need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving
more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote
‘b’ utilization at 75 MW.
Several commenters asked about the distinction between long-term and near-term with respect to the use of footnote ‘b’. The SDT has
clarified the language to show that footnote ‘b’ is available for long-term planning as well as near-term planning but that the
stakeholder process only needs to be used for near-term.
The following changes were made due to industry comments:
First sentence of footnote text: An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

11

Next to last sentences in footnote text: In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to
ensure that BES performance requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term
Transmission Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the use
of Firm Demand interruption meets the conditions shown in Attachment 1.
Organization
Salt River Project
BrightSource Energy, Inc.
Los Angrles Department of Water and
Power
Deseret Generation & Transmission
Cooperative
California Independent System
Operator
nevada power company dba nvenergy
PG&E Company
Utility System Efficiencies, Inc.

Yes or No

Question 1 Comment

No

We do not agree with the imposition of a maximum limit on the amount of
planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. We suggest deleting this sentence.Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly
prescriptive. A single number cannot account for variation even within one
BA Area. This number will be too high for some planning systems and too
low for others.A fixed maximum number of MW for Non-Consequential
Load Loss under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not
necessary. The first sentence of this footnote states, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events”. It is clear that the spirit of the TPL Standard is to minimize the
likelihood and magnitude of Firm Demand interruption. Adding a fix
maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum NonConsequential Load Loss, the Transmission Planner understands that the
objective is to minimize the magnitude of the planned interruption under
footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of
planned Firm Demand loss could have the effect of giving “safe harbor” to
allow planned loss of that amount of load under Footnote b. The
Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed”
amount.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

12

Organization

Yes or No

Question 1 Comment

ACES Power Member Standards
Collaborators

No

We disagree with placing an upper limit on the amount of firm load shed.
Conceptually, it seems like a good idea but we do not believe that such a
threshold could ever consider all of the potential issues that could arise and
would cause the need to plan to shed firm load. This is especially true
considering that the SAR clarifies that the upper threshold will be based on
the existing planned load shedding values. Future issues cannot be
considered by such a data request. Consider a situation in which a new
transmission line was included in Planning Assessment but cannot be built
because right of ways cannot be obtained. Should an upper limit be placed
on planned load shed in such a situation?

Bonneville Power Administration

No

BPA does not support quantitative limits on planned interruption, as
planners generally do not plan the system to interrupt demand for a single
contingency. As stated in the proposed footnote b, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events.” Setting a quantitative limit would push transmission planners to
plan the system to meet such a limit for a single contingency in all cases.
Moreover, a quantitative limit would be difficult to implement due to the
wide variety of system configurations and conditions. BPA believes an
appropriate amount would be dependent on the topography and the size of
the system being planned.

Manitoba Hydro

No

The maximum limit ‘x’ MW should vary with system load level and voltage.
For example, an ‘x’ MW interruption would be a very small fraction of a
5000 MW system load level compared to a 1000 MW load level. Similarly,
interruption of ‘x’ MW could be equal to surge impedance loading of a 230
kV line, where as it would be a fraction of a EHV transmission line loading.

NorthWestern Energy (NWMT)

No

Comments: A fixed maximum number of MW for Non-Consequential Load

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

13

Organization

Yes or No

Question 1 Comment
Loss should not be used in an industry-wide standard. There is too much
diversity. We suggest that a fixed maximum number not be stipulated.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
SERC EC Planning Standards
Subcommittee

No

We do not agree with this approach since there is no technical basis for
allowing load shedding. It is all an administrative process which could result
in inconsistencies from area to area. If a single contingency results in a local
network becoming temporarily radial, then load shedding within the local
network should be allowed. A limitation of up to some maximum amount of
load shedding (to be determined) should be imposed. This would provide a
technical basis for load shedding, which would help ensure consistency.

Southern Company

No

Southern does not agree with this Stakeholder Process approach since
there is no technical basis for allowing load shedding. It is all an
administrative process which could result in inconsistencies from area to
area. A more technical based approach was the one taken by the SDT in an
earlier draft - temporarily radial concept. If a single contingency (Category
B) results in a local network becoming temporarily radial, then load
shedding within the local network should be allowed since it would not
have any impact to the reliability of the transmission grid. A limitation of up
to some maximum amount ('x' MW) of load shedding (to be determined)
should be imposed. This would provide a technical basis for load shedding,
which would help ensure consistency from area to area. Furthermore, this
would provide a method for defining the "fringes" of the power system.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

14

Organization

Yes or No

Question 1 Comment

Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT agrees with you that there should be an upper limit on the amount of Firm Demand that can be shed. Order 762 also
pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
TVA Transmission Reliability
Engineering & Controls

No

TVA believes that the Stakeholder process is burdensome and should not
be required for all levels of footnote b use. TVA beleives that the
Stakeholder process should only be used for larger amounts of planned load
drop. TVA would like to propose the following: For load loss of less than 50
MW - only TP approval is required; for load loss up to 100 MW - PC
approval is required; for load loss up to 300 MW - RRO approval is
required. Any load loss over 300 MW would require both RRO & NERC
approval. The Stakeholder process would be required for any load loss of
100 MW or more. TVA is basing these levels using OE-417 as a starting point
- which must be filed for an uncontrolled load loss of 300 MW as well as
load shedding of 100 MW or more implemented under emergency
operational policy. TVA believes that the 300 MW is the maximum amount
of load that can be dropped without obtaining special permission from both
NERC and the RRO.

Response: The SDT does not agree with this suggestion, as the Order 762 data request showed that there were no utilizations of

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment

footnote ‘b’ involving more than 75 MW. Therefore, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW. The
data request also showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW.
MISO

No

Transmission planning that relies on planned or controlled interruption of
non-consequential firm load following loss of a single transmission facility
should not be acceptable and removal of footnote 12 should be considered
or a modification to allow its use only in conjunction with a petition to FERC
to waive (on an exception basis) the requirement to maintain firm load
service for a specifically identified system configuration issue warranting
Footnote 12’s application. If it is determined that a footnote provision is
required in the standard, we agree with the description and components of
the Stakeholder Process in the body of the footnote, but reserve judgment
on the value of the “x” that sets the maximum amount of MW load loss.
Also, we have comments on the reference to Attachment I. Please see our
comments under Q5.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a stakeholder process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW. Based on this fact,
and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW.
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment

See response to Q5.
San Diego Gas & Electric

No

Public Utility District No. 1 of
Snohomish County

No

We don’t support the changes.

Response: Without any reasons being supplied, the SDT is unable to respond to this comment.
Essential Power, LLC

No

Although we agree with the majority of the content of the footnote, we’re
not sure that using a specific amount of load as the bright-line threshold is
appropriate. For example, if we make the limit 25 MW, this will have a
different impact on different entities, in different regions. For a small TP
that may only have a total of 200 MW of load, 25 MW is a significant
amount of their overall obligation. For an area with 40,000 MW of load, 25
MW is hardly significant. Additionally, the nature of the load must be taken
into consideration as well. Some types of load are more acceptable to lose
than others; again, this may vary from region to region.Although we don’t
have a specific recommendation or solution regarding these issues, I would
urge the SDT to take these into consideration in their next revision.
The sentence that starts with “When interruption of Firm Demand is
utilized...” is confusing as it seems this sentence should only refer to the
limited circumstances mentioned within footnote b

Response: The Order 762 data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT
has kept the process threshold at 25 MW. No change made.
The SDT believes that in context the sentence you reference is clear; no change made.
Tacoma Power

No

The layout of Table 1 with “No 12” does not actually indicate that load loss
is allowed for those specific contingencies. Also the wording of the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
footnote appears to require all Non-Consequential Load Loss to go through
the attachment 1 process, not just P1.1 to P1.5, P2.1 and P3.1 to P3.5.
Instead P1.1 to P1.5 and P3.1 to P3.5 should say “Yes per Attachment I” and
Footnote 12 should be eliminated entirely.
Since P2.1 is a new requirement with Version TPL-001-03, the recent NERC
survey did not capture utilities currently using Non-Consequential Load Loss
to address opening a line without a fault. Furthermore, some utilities may
not identify problem lines until their first assessment using TPL-001-3. P2.1
should have a new footnote reading “For this contingency, load which is
served radial from a remaining single source line may be shed as if it were
Consequential load.” Technical Background: Parallel transmission lines
serving remote load commonly will not perform with a P2-1 contingency,
particularly when the strong source is opened. These issues are particularly
common with load in rural settings and the cost to meet urban reliability
expectations will be disproportionally expensive. Utilities will be
encouraged to configure their system radially, which will be less reliable to
meet this rare contingency. FERC has not specifically addressed load
shedding associated with open ended lines. In order 693 the Commission
was responding to the contingencies in TPL-001-1 that included footnote b.
In order 762 and the NOPR RM12-1-000, FERC continues to reference
applicability of footnote b to the TPL-001 defined single contingencies, but
was otherwise prepared to accept Firm Load Loss for the single
contingencies in TPL-001-2 P2.2 to P2.4. In the TPL-001-2, the category of
“P2-Single Contingency” expanded to include both a new contingency of an
open ended line, and various bus and breaker faults that previously were
considered as Multiple Contingency.Based on our experience the likelihood
of a line opening is significantly less than for line equipment faults. In
addition, during human error caused line open events, personnel are onsite to affect quick restoration.
This standard should not impose an upper limit because any planned large

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
load shedding will be reviewed and approved by the applicable regulatory
authority. Pending the survey outcome, a limit of 3000 MW consistent with
the CIP-002-5 Critical Asset level may be useful if the SDT believes an upper
limit is needed.

Response: The SDT believes that the layout of Table 1 is clear in its intent that the circumstances covered by footnote 12 permit
Load loss by exception and that the footnote pertains only to those Contingency types where the footnote appears. No change
made.
Although P2.1 is a “new” event, the resulting system will be the same as that following many P1.2 events; therefore, the SDT does
not see a need to add a new footnote to P2.1. No change made.
The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed
out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’
involving more than 75 MW. Based on this fact and after reviewing other aspects of the data, the SDT has set the proposed ceiling
on footnote ‘b’ utilization at 75 MW.
Independent Electricity System
Operator

No

Specific to the language used in footnote b, we agree with the concept of
an approval process for determining the acceptable level of Firm Demand
interruption applicable in a jurisdiction, and do not agree with prescribing a
fixed MW threshold for a continent-wide acceptable Firm Demand
interruption.Therefore, we recommend removing the last sentence in
footnote b) which reads “In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed ‘x’ MW.” and also the same
sentence from Attachement 1 section III. We believe there should not be a
fixed limit on the amount of Firm Demand interruption, for reasons
explained below in answers to Questions 4 and 5. As part of a reliability
standard, the footnote should clarify the conditions under which load
curtailment will be allowed, including mention of processes necessary to
manage special circumstances.
We generally agree with the reference to Attachment 1, but have concerns

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
about the components of the Stakeholder Process described in Attachment
1, for reasons described in answers to Questions 2, 3 and 4.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
See responses to Questions 2, 3, 4, and 5.
Ameren

No

We believe that the NERC Glossary contains an adequate definition for Firm
Demand, which does not include Interruptible Demand or Demand-Side
Management Load. We do not believe that Interruptible Demand or
Demand-Side Management Load needs to be mentioned in the footnote b)
as these types of Demand are not Firm Demand. Interruptible Demand can
be cut at any time and may contain Demand-Side Management
components, and may be direct controlled by the System Operator.

Response: The SDT believes that mention of Interruptible Demand and Demand-Side Management Load within footnote ‘b’ adds
further clarity. No change made.
American Transmission Company

No

ATC agrees with the ‘x’ MW statement in footnote ‘b’ , however, supports a
maximum threshold value of 300 MW because this is the load loss
threshold that the DOE deems to be significant enough to warrant a NERC
system event investigation.

Response: The SDT does not agree with this suggestion. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
Salt River Project

No

Additional comment from SRP for Q #5.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Consolidate Edison Co. of NY, Inc.

Question 1 Comment

No

See reply to Question 5

No

LES suggests the following changes to Footnote B/12 to further clarify the
drafting team’s intent. Under Footnote B/12, recommend the first sentence
be modified to state “An objective of the planning process is to minimize
the likelihood and magnitude of interruption...”.

Response: Please see response to Q5.
Lincoln Electric System

Additionally, please clarify the reference to the Near-Term Transmission
Planning Horizon while remaining silent on the Long-Term Transmission
Planning Horizon. Does Appendix 1 apply to the Long-Term Transmission
Planning Horizon as well as the Near-Term Transmission Planning Horizon?
Response: The SDT agrees with your suggested substitution of the word “is” for the words “should be” in the first sentence of the
footnote.
An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events.
The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term planning, but
that the stakeholder process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
LCRA Transmission Services Corporation

No

Footnote 12 is applied in column labeled “Non-Consequential Load Loss
Allowed.” However, the last sentence of the proposed Footnote 12
switches from using the terms Consequential Load Loss and NonConsequential Load Loss to using the term “Firm Demand.” The term “Firm
Demand” should be revised to “non-Consequential Load Load loss.”

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
In addition, the application of Footnote 12 to the P3 contingency category
should be removed.

Response: The SDT agrees with your change and will use the term “Non-Consequential Load loss.”
The SDT does not agree that footnote 12 should be removed from the P3 Contingency category. The SDT clarifies that the Planning
Events for which footnote 12 is applicable were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011)
in its consideration of TPL-001-2. The proposed changes are outside the scope of this project, which aims to clarify the stakeholder
approval process. No change made.
Tri-State Generation & Transmission
Association, Inc.

No

There are several points that we disagree with in terms of the Stakeholder
Process in the body of the footnote. First, the footnotes are not written in a
manner so as to clearly be only applicable to Planning Standards. Many
parts of the footnotes and the Attachment I can be misconstrued as
Operational requirements. For example, the sentence that states
“Curtailment of firm transfer...” should state “Planned curtailment of firm
transfer...”
Second, we disagree with the imposition of a maximum limit on the amount
of planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. We suggest removal of this sentence.Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly
prescriptive. A single number cannot account for variation even within one
BA Area. This number will be too high for some planning systems and too
low for others.A fixed maximum number of MW for Non-Consequential
Load Loss under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not
necessary. The first sentence of this footnote states, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events”. It is clear that the spirit of the TPL Standard is to minimize the
likelihood and magnitude of Firm Demand interruption. Adding a fixed

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum NonConsequential Load Loss, the Transmission Planner understands that the
objective is to minimize the magnitude of the planned interruption under
footnote b (TPL-001-3, footnote 12).
Lastly, in an effort to develop a clearer and more transparent compliance
standard, it is recommended that the additional requirements imposed by
this footnote be broken into separate requirements set forth within the
body of the standard itself. Do not imbed requirements in footnotes.

Response: Because this footnote can only be applied to this specific standard, there should be no confusion as to the applicability to
planning. No change made.
The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed
out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’
involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling
on footnote ‘b’ utilization at 75 MW.
The SDT disagrees with your characterization that requirements are being imbedded within the footnote. The requirement is clearly
stated within the body of the standard. The footnote is simply clarifying those special circumstances where some relief from a strict
interpretation of the requirement is permitted. No change made.
Hydro-Quebec TransEnergie

No

Comments: It is difficult to establish the maximum value for acceptable
Firm Demand interruption. For example, an entity may have an acceptable
maximum load loss to avoid impacts on the grid such as generation tripouts. For Hydro-Québec TransÉnergie (HQT), in the Québec
Interconnection, this value is above 1,000 MW. No maximum value should
be posted in Footnotes 12 and ‘b’, since it is specifically related to system
design and Interconnection size (inertia). Let us keep in mind that the goal
of the TPL standards is not service continuity of local loads but global
reliability of the system. Even though service continuity is important, TPL

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
standards should not address this issue by posting a maximum allowable
load loss.
Moreover, HQT considers that a Stakeholder Process such as seen in
Attachment I has no place in a standard and its footnotes. Mainly, the
Stakeholder Process doesn’t consider that entities may have their own
regulatory authorities with different processes, which do not specifically
establish this load loss value.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
Industry and the NERC BOT have approved the use of a Stakeholder Process to address the concerns with the original footnote ‘b’
and with footnote 12 in TPL-001-2. The SDT is now attempting to address FERC’s concern expressed in their Remand Order 762 that
NERC’s proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load
shed in a single Contingency provided that the plan is documented and alternatives are considered in an open and transparent
process, is vague, unenforceable, and not responsive to the previous Commission directives on this matter. The draft posted for
comment adds detail and specificity to the already-approved approach. The SDT does not believe it appropriate to move away from
the industry and BOT approved Stakeholder Process approach. No change made.
Exelon

No

For TPL-001, the wording for footnote 12 does not make clear that DSM
would be allowed without the Attachment 1 procedure. ComEd suggests
the following wording change:12. An objective of the planning process
should be to minimize the likelihood and magnitude of Non-Consequential
Load Loss following Contingency events. However, in limited circumstances
Non-Consequential Load Loss may be needed to ensure that BES
performance requirements are met. When Non-Consequential Load Loss is
utilized within the planning process to address BES performance
requirements (other than Interruptible or Demand Side Management load),
such interruption is limited to circumstances where the Non-Consequential

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
Load Loss is meets the conditions shown in Attachment 1. In no case can
the planned Firm Demand interruption under footnote 12 exceed ‘x’ MW.
For TPL-002, the wording of footnote “b” is not totally clear that it applies
only to non-consequential load shed and not consequential load shed.
ComEd suggests that the wording of footnote “b” be changed as shown:b)
An objective of the planning process should be to minimize the likelihood
and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm
Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the
Contingency, or (2) Interruptible Demand or Demand-Side Management
Load. Furthermore, in limited circumstances Firm Demand may need to be
interrupted to ensure that BES performance requirements are met. When
interruption of Firm Demand (other than in (1) or (2) above) is utilized
within the planning process to address BES performance requirements,
such interruption is limited to circumstances where the use of Firm Demand
interruption meets the conditions shown in Attachment 1. In no case can
the planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW.

Response: The SDT believes that footnote 12, as written and taken in context of the entire proposed TPL-001-2a standard, is clear.
Similarly, the SDT believes that footnote ‘b’ is clear, as well. No change made.
ISO New England Inc.

No

For single contingency events, footnote 12 should be eliminated. Planning
the electric system for non-consequential load loss as a means to address a
single contingency should not be acceptable.
If the footnote is to remain, as a minimum the attachment should be

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
changed to increase the emphasis on the near term nature of the use of
non-consequential load shedding.

Response: The SDT disagrees with your suggestion to remove footnote 12 because there are some limited situations when
considering the entire North American grid where Non-Consequential Load loss may be necessary. No change made.
The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term planning, but
that the stakeholder process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
South Carolina Electric and Gas

No

SCE&G does not agree with the proposed modifications to footnote b.
SCE&G believes the original footnote b is appropriate and consistent with
the Energy Policy Act of 2005.SCE&G cites several statements in the Energy
Policy Act of 2005 as justification for our position.1. The Energy Policy Act
of 2005 states: “The term ‘reliability standard’ means a requirement,
approved by the Commission under this section, to provide for reliable
operation of the bulk-power system. The term includes requirements for
the operation of existing bulk-power system facilities, including
cybersecurity protection, and the design of planned additions or
modifications to such facilities to the extent necessary to provide for
reliable operation of the bulk-power system, but the term does not include
any requirement to enlarge such facilities or to construct new transmission
capacity or generation capacity."It also states, “This section does not
authorize the ERO or the Commission to order the construction of
additional generation or transmission capacity or to set and enforce
compliance with standards for adequacy or safety of electric facilities or
services.”SCE&G believes the proposed modifications to footnote b will
result in building or enlarging facilities to meet the proposed requirements.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
Also, any requirement that disallows load interruption or limits the amount
of load interruption infringes on the stated limitation on the ERO to not set
and enforce compliance with standards for adequacy.2. It also states: The
term ‘reliable operation’ means operating the elements of the bulk-power
system within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of
such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements.”In this
statement there is no mention of disallowing the interruption of firm load.
It only requires that instability, uncontrolled separation, or cascading
failures not occur. SCE&G believes the proposed changes to footnote b are
beyond the authority granted to the ERO by the Energy Policy Act.3. It also
states: ‘‘Nothing in this section shall be construed to preempt any authority
of any State to take action to ensure the safety, adequacy, and reliability of
electric service within that State, as long as such action is not inconsistent
with any reliability standard, ..."SCE&G believes the proposed modifications
to footnote b infringe on the state’s authority to address adequacy and
reliability of electric service within the State.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Electric Reliability Council of Texas, Inc.

Yes or No

Question 1 Comment

No

As an initial matter, ERCOT does not believe the planning process should
allow for non-consequential load shedding under single contingency
conditions. However, if the SDT elects to retain a vehicle for such
exceptions, it should establish objective, reliability based criteria that lend
themselves to inclusion in a reliability standard. This is consistent with the
general approach for reliability standards, which prescribe the “what”, not
the “how”. If the exceptions are based on objective criteria that are known
upfront, and those criteria reflect appropriate reliability based technical
justifications, then the risk of unwarranted exceptions to the general
prohibition due to misuse of the exception process is mitigated.
Furthermore, the exception process should be external to the NERC
Reliability Standards (e.g. in the Rules of Procedure), which should merely
reference authorized exceptions granted pursuant to that process. In no
case should a reliability standard mandate a stakeholder process in any
respect, procedural or substantive. In ISO/RTO regions, stakeholder
processes fall within ISO/RTO governance matters. These issues are beyond
the purview of NERC Reliability Standards. In other regions, although the
relevant functional entities do not have stakeholder processes analogous to
ISOs/RTOs, any relevant processes are similarly beyond the scope of the
reliability standards. Accordingly, the SDT should eliminate all revisions
related to the establishment of a stakeholder process. As discussed in
response to question 5, FERC is not requiring this approach, but rather has
only provided guidance with respect to ways to possibly bring the prior
proposal in line with applicable regulatory approval standards for reliability
standards.
Additionally, as a general matter, substantive reliability standards
requirements should not be imbedded within a footnote to a requirement.
In this case, not only is there a substantive requirement imbedded in the
footnote, there is also a substantial attachment (which must become part
of the enforceable standard requirements)...and, to make it worse, the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment
attachment is an attachment to the footnote, rather than an attachment to
and referred to by a reliability standard requirement.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT disagrees with your characterization that requirements are being imbedded within the footnote. The requirement is clearly
stated within the body of the standard. The footnote is simply clarifying those special circumstances where some relief from a strict
interpretation of the requirement is permitted. No change made.
Modesto Irrigation Districtt

No

We do not agree with the concept of non-consequential load loss in light of
historic application of N-1 criteria, that only provides for consequntial load
loss.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 1 Comment

would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Southwest Power Pool Reliability
Standards Development Team

Yes

As a concept we agree with the stakeholder process. We would like
clarification on why only the Near Term was used for non-consequential
load loss and not both Near and Long term. It seems that depending on the
time frame we would be held to different requirements of the standard.

Response: The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term
planning, but that the Stakeholder Process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
MRO NSRF

Yes

The NSRF agrees with the ‘x’ MW statement in footnote b. The NSRF
suggests a maximum threshold value of 300 MW because this is the load
loss threshold that the DOE deems to be significant enough to warrant a
NERC system event investigation.To support the inclusion of planning to use
up to 300 MW of firm load shedding, registered Transmission Planning
entities or regional planning entities should provide a TPL type analysis that
demonstrates the use of planned firm load shedding allows BES equipment
to stay within emergency thermal, voltage, and frequency ranges, and
would not cause instability, uncontrolled separation, and cascading as
defined in the FPA Section 215.

Idaho Power Co.

Yes

Maximum threshold for Planned Firm Demand interruption should be
based on a previous year recorded peak demand. For instance for recorded
peak demand of more than 3,000 MW the maximum treshold should be

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

30

Organization

Yes or No

Question 1 Comment
greater than 300 MW.

Duke Energy

Yes

Situations where use of footnote ‘b’ would be appropriate can’t be readily
characterized with criteria leading to some “technically justified” maximum
capacity threshold for interruption. That being the case, a maximum
capacity threshold could be established based upon other criteria, such as
the 300 megawatt threshold for DOE disturbance reporting.

Response: The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW. Based on
this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW.
Georgia Transmission Corporation

Yes

Please remove the “is” as shown below:”12. An objective of the planning
process should be to minimize the likelihood and magnitude of NonConsequential Load Loss following Contingency events. However, in limited
circumstances Non-Consequential Load Loss may be needed to ensure that
BES performance requirements are met. When Non-Consequential Load
Loss is utilized within the planning process to address BES performance
requirements, such interruption is limited to circumstances where the NonConsequential Load Loss [IS] meets the conditions shown in Attachment 1.
In no case can the planned FirmDemand interruption under footnote 12
exceed ‘x’ MW.”

Response: The SDT agrees with your suggested substitution of the word “is” for the words “should be” in the first sentence of the
footnote.
An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events.
LCEC (Lee County Electric Cooperative
American Electric Power

“No comment as we have no Firm Demand / Load customers.”
Yes

AEP believes it can support the language at this stage, but would like to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

31

Organization

Yes or No

Question 1 Comment
revisit this after the MW threshold has been determined.

Arizona Public Service Company

Yes

Orlando Utilities Commission

Yes

CPS Energy

Yes

City of Austin dba Austin Energy

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

32

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of Attachment I? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Comments raised several concerns on the following issues:
Stakeholder process is not needed: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address
the concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s
proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a stakeholder process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Proposed process duplicates or conflicts with existing regulator/RTO processes: The SDT agreed with the comments and revised
Footnote 12 accordingly. The text now allows for an existing process to be utilized, as long as it meets the criterion set out in
Attachment 1, Section I.
Scope of Stakeholder Participants: Some comments reflected concern that the term “all affected stakeholders” in Attachment 1, Part I
was too broad. The SDT has accepted the commenters’ view and has deleted ‘all’.
Clarification on need for annual Stakeholder Review: Commenters requested clarification as to whether the stakeholder processes has
to be repeated for each annual assessment for a project if the process has confirmed for that specific project it is acceptable to curtail a
firm demand. The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual
assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

33

Part I 2 b. Public Notification: The SDT agrees with the comment that: “Specific applications of the planned Firm Demand interruption
under footnote 12” could be considered to require detailed descriptions of each and every contingency that could lead to use of
footnote ‘b’ and is not necessary for the public notification. The language has been changed to clarify the SDT’s intent.
Implementation Plan: Several commenters mentioned that this process could turn out to be lengthy and that the Implementation Plan
should take this into account. The Implementation Plan for this project hasn’t changed from the one that was submitted with the
original filing, and is currently set at 60 months for footnote ‘b’.
Dispute resolution process is not required: The SDT concluded that a dispute resolution process is an essential part of the process. The
attachment language does not present any constraints on such a process; it just requires that an entity has a method to resolve
disputes.
The following changes were made due to industry comments:
Main Body of footnote text: In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that
BES performance requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission
Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Attachment 1 – Section I, last sentence: The responsible entity can utilize an existing process or develop a new process. The process
must include the following:
Attachment 1 – Section I, Bullet 1: Meetings must be open to affected stakeholders including applicable regulatory authorities or
governing bodies responsible for retail electric service issues
Attachment 1 – Section 1, Bullet 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:
Attachment 1 – Section I, Bullet 2b: Specific location(s) of the planned Firm Demand interruption under footnote ‘b’
Attachment 1 – Section I, last paragraph: An entity does not have to repeat the stakeholder process for a specific application of
footnote ‘b’ utilization with respect to subsequent Planning Assessments unless conditions spelled out in Section II below have
materially changed for that specific application.
Organization

Yes or No

Salt River Project

No

Question 2 Comment
We suggest removing item 5, “A dispute resolution process for any question or
concern raised in #4 above that is not resolved to the stakeholder’s satisfaction”.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

34

Organization

Yes or No

BrightSource Energy, Inc.

Question 2 Comment
Given that the “applicable regulatory authorities or governing bodies responsible for
retail electric service issues” are only one of the many affected stakeholders, it is
unclear how this dispute resolution process would treat stakeholders with different
concerns. For example, how would such a dispute resolution process take into
account the cost-benefit balance of load loss, which is the responsibility of the
authorities responsible for retail rates, if such an authority is only one of the many
stakeholders subject to dispute resolution?

Los Angrles Department of
Water and Power
Deseret Generation &
Transmission Cooperative
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation District
Utility System Efficiencies, Inc.

Response: The SDT believes that a dispute resolution process is an essential part of the Stakeholder Process. The SDT believes that
the dispute resolution process should include a method for accounting for the cost/benefit if it is an issue for the region. The
attachment language does not present any constraints on such a process; it just requires that an entity has a method to resolve
disputes. No change made.
MRO NSRF

No

American Transmission
Company

Order 890 already requires Transmission Planners to solicit the input of affected
stakeholders on TPL standards. Order 890 does not provide prescriptive details
regarding the stakeholder process for the TPL standards, which includes footnote ‘b’.
In additions, there is no clear justification to indicate that the process with regard to
footnote ‘b’ warrants more prescription stakeholder process details than the rest of
the TPL standards. So, the NSRF suggests that Section II be removed.
If Section I is not removed, then NSRF suggests at least replacing “all affected
stakeholders” with “all known affected stakeholders” or “appropriate known affected
stakeholders” because an entity can develop a list of all known affected entities for
compliance purposes and document that the meeting was open to them and that
they were notified. An entity cannot demonstrate that a stakeholder meeting is open

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

35

Organization

Yes or No

Question 2 Comment
to unknown stakeholders or that it notified unknown stakeholders.The use of “all” in
mandatory zero defect standards is not appropriate in NERC standards, especially
when potential large diverse populations such as affected stakeholders must be
considered.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT has tried to provide some technical/quantitative criteria in Section II to assist affected stakeholders in understanding why
Firm Demand is planned to be interrupted. No change made.
The SDT has accepted your comment and has replaced “all affected stakeholders” with “affected stakeholders.”
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
retail electric service issues
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:
TVA Transmission Reliability
Engineering & Controls

No

Please see comment for question #1. TVA believes that TPs should be able to drop
some load without having to go thru a burdensome process. Only the larger load
drop levels should require a Stakeholder review.

SERC EC Planning Standards

No

We recommend using a technical basis for load shedding instead of a Stakeholder

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

36

Organization

Yes or No

Subcommittee
Southern Company

Question 2 Comment
Process.

No

Southern recommends using a technical basis for load shedding (see comment in
Question 1 above) instead of a Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Please also see response to Q1.
ACES Power Member
Standards Collaborators

No

(1) Attachment 1 should clarify that it only applies when approval is not required by
the regulatory body with authority over retail service, such as local regulatory
authorities and state public utility commissions. This includes whether the approval
is required by NERC rules or another regulatory body’s rules. It does not make sense
for the Transmission Planner or Planning Coordinator to duplicate a process that is
already required by another regulatory body that satisfies due process. As an
example, why should the Transmission Planner and Planning Coordinator have a
dispute resolution process if the regulatory body already has a dispute resolution
process that can be used. It also does not make sense for the Transmission Planner
and Planning Coordinator to be compelled to have a stakeholder comment process
when the local regulatory body’s approval is required. Having such a process is
duplicative and unnecessary.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

37

Organization

Yes or No

Question 2 Comment
(2) Many RTOs have well organized stakeholder processes that could be utilized to
satisfy Attachment I. Because the TPL standards apply to both the PC and TP, one
may believe the both the PC and TP need to have these stakeholder processes.
Rather, we think that the TP should be able to rely on its PC’s stakeholder process.
We suggest Attachment I should clarify that this is acceptable and that both entities
are not required to have redundant processes. The most important point is that
stakeholders have an opportunity to participate.

Response: The SDT has revised the Stakeholder Process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following:
The SDT believes that a dispute resolution process is an essential part of the stakeholder process. No change made.
Bonneville Power
Administration

No

Regarding the stakeholder process and dispute resolution, BPA believes that a
decision for Firm Demand interruption needs to be made based on what is best for
the system, not a specific dispute resolution process.

Western Area Power
Administration

No

The addition of the "Stakeholder Process" outlines in Attachment 1 is so onerous so
as to persuade entities NOT to attempt the use of Footnote b) OR 12). Is this the
intent?

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

38

Organization

Yes or No

Question 2 Comment

not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
MISO

No

(1) The process presented in Section I of Attachment I is overly prescriptive. This
Section needs only to stipulate that the proposed utilization of the footnote be
reviewed through an open and transparent stakeholder process developed or
approved by the Regional Entities (since the RE will eventually need to review and
assess the reliability impact of such utilization), with supporting information.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered and adopted, subject to
stakeholder’s and regulatory authority’s approvals. Note that it is impractical to add
or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame
and hence the proposed provision does not allow for utilizing the footnote for the
interim period before new or reinforced transmission facilities are put in place. We
suggest to remove the word “Near-Term”.
(3) Requirement 8 of the Transmission Planning Standard TPL-001-3 requires
notification and response requirements for a Planning Coordinator and/or
Transmission Planner for the Planning Assessment to any registered entity having a
reliability interest. Attachment I does not recognize this requirement. Attachment I
must be coordinated with this administrative requirement.

Response: (1) Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns
with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

39

Organization

Yes or No

Question 2 Comment

remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
(2) The Stakeholder process is required prior to planned interruption of Firm Demand in the near term, but does not preclude
application in the long term. The SDT clarified the language concerning near- and long-term applications of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
(3) Requirement R8 imposes an obligation on the Planning Coordinator and Transmission Planner to distribute its Planning
Assessment to: “any functional entity that has a reliability related need and submits a written request for information …”
Requirement R8 does not ensure the functional entity is aware that it may be affected by a plan to curtail firm Load so as to request
information. If a Planning Coordinator or Transmission Planner has established a stakeholder process, as per Attachment 1,
reporting of such a process under Requirement R8 is not prohibited. No change.
Public Utility District No. 1 of
Snohomish County

No

San Diego Gas & Electric

No

We don’t support the addition of stakeholder process language.

Response: With no reasoning provided, the SDT is unable to respond to this comment.
Tacoma Power

No

Completing the entire stakeholder process on an annual basis, before the TPL study
can be finalized, is not feasible due to long and unpredictable timelines for public
involvement and regulatory approval. The stakeholder process should only be
repeated when the technical basis as outlined in section II have changed, or when

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

40

Organization

Yes or No

Question 2 Comment
there are new stakeholders.
There are cases on the fringes of the system where Firm Demand Interruption as the
preferred alternative in both the long term and short term, not as a temporary patch
in Corrective Action Plan.To address these issues, Section I should read as:Before the
use of Firm Demand interruption is allowed as an element in the Transmission
Planning Horizon of the Planning Assessment, the Transmission Planner or Planning
Coordinator shall ensure that the utilization of this mitigation is reviewed through an
open and transparent stakeholder process. The responsible entity shall document
the stakeholder process which shall include the following:1. Meetings must be open
to all 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 all 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
applications of the planned Firm Demand interruption under footnote 12 c.
Provisions for a stakeholder comment period 3. Information regarding the intended
purpose and scope of the proposed Firm Demand interruption 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. During each Planning Assessment, the Transmission
Planner or Planning Coordinator shall update the information outlined in Section II. If
the annual hours of exposure to or the amount of Firm Demand has increase above
the previously disclosed level(s), a new Stakeholder process shall be completed
within one Calendar year.Every three years the stakeholder process shall reoccur to
allow new stakeholders input to the process.

Response: The SDT has not adopted your proposed language: “Before the use of Firm Demand interruption is allowed as an element
in the Transmission Planning Horizon of the Planning Assessment,” as the SDT believes the reference to the Corrective Action Plan is

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

41

Organization

Yes or No

Question 2 Comment

superior. However, the SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each
annual assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has already provided a 60-month
implementation plan. No change made.
The information in Section II is required as part of the Stakeholder meeting. No change made.
Manitoba Hydro

No

A stakeholder process should not be required in jurisdictions where a legislation
already authorizes interruptions, as consent of stakeholders cannot override
legislation. If Firm Demand interruptions require the approval of regulatory authority
as described in Section III (for interruptions over 25 MW or if voltage level of the
contingency is greater than 300 kV), the stakeholder process described in Section I
would become a redundant process.
Does Section I exclude Firm Demand interruptions addressed under Section III?

Response: The SDT has revised the stakeholder process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
For interruptions over 25 MW, or if voltage level of the Contingency is greater than 300 kV, then both the Stakeholder Process and
the Section III regulatory review are still required.
Independent Electricity
System Operator

No

(1) The process presented in Section I and the rest of Attachment I is overly
prescriptive and lengthy. As part of a reliability standard, the footnote and process
must focus on the impact that Firm Demand interruption (or Load Rejection) would

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

42

Organization

Yes or No

Question 2 Comment
have on the reliability of the Bulk Electric System and this aspect is covered in Section
III. This Section needs only to stipulate that the proposed utilization of the footnote
be reviewed through (a) an open and transparent stakeholder process and (b)
approved by a relevant reliability authority such as the ERO, Regional Entity or
applicable governmental authority since this authority will eventually need to review,
assess and approve the reliability impact on the interconnected BES of such
utilization, with supporting information. Reliability issues and their assessment and
approvals should be dealt with by the applicable reliability authority. Details of other
aspects of Firm Demand interruption, mainly the Stakeholder review and approval
process and issues pertaining to the quality of service, economic and welfare impacts
of Firm Demand interruption, assessment of alternatives (including their economic
and welfare impacts), etc. should be dealt with by the regulatory authority or
government body of each jurisdiction (in particular, in non-US jurisdictions), as is the
normal practice for all other Transmission Planning activities.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered and adopted, subject to
stakeholders’ and regulatory authorities’ approvals. Note that it is impractical to add
or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame
and hence the proposed provision does not allow for utilizing the footnote for the
interim period before new or reinforced transmission facilities are put in place. We
suggest removing the word “Near-Term”.

Response: (1) The SDT believes that the stakeholder process must involve all stakeholders affected and provide specific information
of the intended purpose and scope so they can understand the reason for Firm Demand interruption is appropriate. Industry and the
NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original footnote ‘b’ and
with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning Reliability

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

43

Organization

Yes or No

Question 2 Comment

Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that the plan is
documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable, and not
responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal as unjust,
unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not because it
contained a Stakeholder Process, but because they wanted the process better defined including a blend of quantitative and
qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft added
detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to move away
from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has provided a 60-month
implementation plan.
(2) The Stakeholder process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Ameren

No

We request that Item 1 be modified to include representatives of stakeholders
because it may not be practical to open a meeting to all affected stakeholders. The
new sentence of Attachment 1 should read, “Meetings must be open to all affected
stakeholders, or their representatives, including applicable regulatory authorities or
governing bodies responsible for retail electric service issues.”
Also, requirements for a meeting location would sem to eliminate electronic
partipation via webex. It would seem more practical for a TP or PC to host a specific
webex to present and discuss the issues associated with the need to drop Firm
Demand.
Further, we request that a MW threshold be included before the Section I
stakeholder process would begin, and believe that a minimum threshold of 10 MW of
Firm Demand to be cut would be a reasonable value to initiate a stakeholder process.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

44

Organization

Yes or No

Question 2 Comment
Levels below 10 MW would be considered as “noise” in the planning horizon. We
believe that an approval should be obtained in the Section I process, which would
eliminate the need for Section III. By requiring an approval of the appropriate local
governing bodies responsible for retail service issues (including rates), there is no
need to agree on a cap to limit the amount of Firm Demand dropped.

Response: The SDT agrees that the term “all affected stakeholders” in Attachment 1, Part I is too broad. The SDT has accepted the
commenters’ view and has replaced “all affected stakeholders” with “affected stakeholders.” The SDT has not included stakeholder
representatives, as this too would make identification of same impossible.
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
retail electric service issues
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:
The Stakeholder Process in Attachment 1 assumes that a meeting would be held; however, the language does not prohibit the use of
other methods acceptable to the stakeholders.
Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning
Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that
the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable,
and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal as
unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not
because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of quantitative
and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft
added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to
move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

45

Organization

Yes or No

Salt River Project

No

Question 2 Comment
Additional comment from SRP for Q #5.

Response: Please see response to Q5.
LCRA Transmission Services
Corporation

No

In the Proposed Revision to the Standard, Footnote 12 is applicable to the use of
Non-Consequential Load Loss to relieve criteria violations resulting from P1, P2, and
P3 category contingencies, however, Footnote 12 and Attachment I switch terms and
begins using “Firm Demand.” Though it may be reasonable to characterize NonConsequential Load Loss as a subset of Firm Demand not all Firm Demand is NonConsequential Load Loss. The term “Firm Demand” as used in Footnote 12 and
Attachment I should be replaced with “Non-Consequential Load Loss.” Application of
the term “Firm Demand” in Footnote 12 and Attachement 1 introduces an ecomonic
criteria to the TPL-001 Reliability Standard. For intstance, the interruption of “Firm
Demand” as defined in the NERC Glossary may not require Non-Consequential Load
Loss, however, this is an economic decision between the parties involved in the Firm
Demand contract. In addition, a Transmission Planner or Tranmission Owner may or
may not be a party to the Firm Demand contract.
The process outlined in Attachment 1 applies to the P3 contingency category
(through the application of Foontote 12) and thus represents a significant and
substantive change in the reliability standard over previous standards. The reference
to Footnote 12 should be deleted from the P3 contingency category.

Response: The SDT acknowledges that the references to Firm Demand interruption should reference Non-Consequential Load Loss.
The SDT has made revisions to the TPL-001-2a Footnote 12 and Attachment I to show these changes.
The SDT clarifies that the planning events for which footnote 12 is applicable were already vetted by industry and the NERC Board of
Trustees (approved on 8/4/2011) in its consideration of TPL-001-2. The proposed changes are outside the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
Tri-State Generation &

No

We disagree with Section I of Attachment I to the extent that there currently are
several other venues through which stakeholder input is mandated. In addition, we

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

46

Organization

Yes or No

Transmission Association, Inc.

Question 2 Comment
do not believe NERC Reliability Standards have the authority to dictate stakeholder
outreach processes. For several reasons, including the time required for public input,
permitting, acquisition, and construction, most transmission projects take several
years to build. TPs will develop plans to mitigate BES performance violations, but
those plans may not be able to be constructed in time. The Footnotes do not allow
planners to design temporary mitigation to accommodate real world construction
issues, which are often complex in nature due to competing interests.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has provided a 60-month
implementation plan.
Duke Energy

No

Since item 2 describes the public notice that must be provided, the phrasing of 2.b
should be revised to replace the words “Specific applications” with the words
“Summary description”. “Specific applications” could be considered to require
detailed descriptions of each and every contingency that could lead to use of
footnote ‘b’. That level of detail could certainly be provided to meeting participants,
but shouldn’t be necessary for the public notice.

Response: The SDT agrees with the comment that: “Specific applications of the planned Firm Demand interruption under footnote

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

47

Organization

Yes or No

Question 2 Comment

12” could be considered to require detailed descriptions of each and every contingency that could lead to use of footnote ‘b’ and is
not necessary for the public notification. The language has been changed to clarify the SDT’s intent.
Specific location(s) of the planned Firm Demand interruption under footnote ‘b’.
California Independent
System Operator

No

The process presented in Section I of Attachment I is overly prescriptive. Identifying
the need for stakeholder consultation on this issue within the consultation process
already employed by the Transmission Planner or Planning Coordinator should be
sufficient detail. In particular, however, we suggest removing item 5, “A dispute
resolution process for any question or concern raised in #4 above that is not resolved
to the stakeholder’s satisfaction”. Given that the “applicable regulatory authorities
or governing bodies responsible for retail electric service issues” are only one of the
many affected stakeholders, it is unclear how this dispute resolution process would
treat stakeholders with different concerns. For example, how would such a dispute
resolution process take into account the cost-benefit balance of load loss, which is
the responsibility of the authorities responsible for retail rates, if such an authority is
only one of the many stakeholders subject to dispute resolution?
There is no basis to support only allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment. The footnote itself
leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered. Note that it is impractical
to add or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time
frame and hence the proposed provision does not allow for utilizing the footnote for
the interim period before new or reinforced transmission facilities are put in place.
We suggest removing the word “Near-Term”.

Response: The SDT has recognized that the requirement to notify all stakeholders is too broad and has replaced “all affected
stakeholders” with “affected stakeholders.”
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

48

Organization

Yes or No

Question 2 Comment

retail electric service issues
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:
The SDT believes the stakeholder process is required and it must provide specific information of the intended purpose and scope so
stakeholders can understand the reason for Firm Demand interruption is appropriate. The SDT has debated the language and believe
that it is appropriate. No change made.
The Stakeholder Process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Hydro-Quebec TransEnergie

No

The Stakeholder Process doesn’t consider that entities may have their own regulatory
authorities with different processes, which do not specifically establish load loss
values. Also, the use of Firm Demand interruption in the Corrective Plan should not
be limited only to the Near-Term Transmission Planning Horizon. It should also be
allowed for the Long-Term horizon, at least for Multiple Contingencies.

Response: The SDT has revised the Stakeholder Process to allow use of an existing regulator/RTO Stakeholder Process, as long as it
meets the criterion set in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
The Stakeholder process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

49

Organization

Yes or No

Question 2 Comment

Demand interruption meets the conditions shown in Attachment 1.
NorthWestern Energy
(NWMT)

No

Comments: It is unclear how the dispute resolution process would treat stakeholders
with different concerns. We suggest that Item 5 of Attachment 1 be deleted.

Response: The SDT believes that a dispute resolution process is an essential part of the Stakeholder Process. No change made.
Georgia Transmission
Corporation

No

Item #1 in Section I should be reworded: From This....”Meetings must be open to all
affected stakeholders including applicable regulatory authorities or governing bodies
responsible for retail electric service issues.” Reworded to say: “Meetings must be
open to all affected NERC Registered Entities including applicable regulatory
authorities or governing bodies responsible for retail electric service issues.”The
concern is that stakeholders could be too broadly construed including residential,
commercial, industrial customers, and even more so (i.e transitory customers). We
recommend that the sentence be reworded as shown above.
Additionally, GTC request feedback from the SDT's intent. Is a stakeholder meeting
required every year a planning assessment is done showing that non-consequential
load loss is required?

Response: The SDT believes that the current language is clear and that the suggested change does not add further clarity. No change
made.
The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual assessment if the
process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the parameters have not
changed. If any changes have occurred to the original parameters, these issues must then be addressed in the Stakeholder Process
before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

50

Organization
ISO New England Inc.

Yes or No

Question 2 Comment

No

With regard to Section I, in paragraph I.5, the stakeholder process includes a dispute
resolution process. Existing ISO/RTO stakeholder processes are FERC approved and
rigorous, requiring a dispute resolution process goes beyond the existing
requirements in ISO/RTO tariffs. Item I.5 should be eliminated.

Response: The SDT has revised the stakeholder process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion set in Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
The SDT concluded that a dispute resolution process is an essential part of the process and no change was made to the process.
South Carolina Electric and
Gas

No

See response to question #1

Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT’s response to Question 1.

Southwest Power Pool
Reliability Standards
Development Team

Yes

See comment From question 1

Response: Please see response to Q1.
Lincoln Electric System

Yes

Although LES agrees in general with the description and components included as part
of Section I, we suggest the following wording changes to enhance Section I.
Recommend the drafting team delete item 2(c) as it is duplicative of item 4 which is
more succinctly worded. Also, recommend additional wording be added to the end of
item 3 to provide meeting participants with advanced notice of the information. As
an example, “information...must be made available to meeting participants [ten days
prior to the meeting].”

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

51

Organization

Yes or No

Question 2 Comment

Response: The SDT believes that the current language is clear and that the suggested change does not add further clarity. No change
made.
LCEC (Lee County Electric
Cooperative

No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

Arizona Public Service
Company

Yes

Orlando Utilities Commission

Yes

CPS Energy

Yes

Essential Power, LLC

Yes

American Electric Power

Yes

City of Austin dba Austin
Energy

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

52

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of Attachment I? If you do
not support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the
concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Based on industry comment, item 8 of Section II has been modified to clarify that adjacent Transmission Planners and Planning
Coordinators are the relevant parties for assessment of potential overlapping use of Firm Demand interruption.
Based on industry comment, item 2.b of Section II has been modified to clarify the SDT’s intent. However, the SDT believes assessment
of the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for understanding the
reliability impact and for stakeholders to make an informed decision. Such an assessment is already required under EOP-001-2.1b by
the Transmission Operator and Balancing Authority. A similar requirement for the Transmission Planner/Planning Coordinator would
rely on the same type of information and sources already required under the EOP standard.
Several commenters had concern about being required to provide the information in Section II, items 1, 2, 3 and 4. The SDT believes
that this information is necessary for understanding the reliability impact and for stakeholders to make an informed decision.
The following changes were made due to industry comments:
Attachment 1, Section II, Bullet 2b: Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health,
safety, and welfare of the community

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

53

Attachment 1, Section II, Bullet 8: Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent
Transmission Planners and Planning Coordinators
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.
Organization
Southwest Power Pool
Reliability Standards
Development Team

Yes or No

Question 3 Comment

No

We need clarification on the term planner in item 8 of section 2. Since the term isn’t
capitalized we would like to know if this was intended to mean Transmission Planner
or a adjacent Planning Coordinator for identifying a seams issue.
We would like see item 2b of section 2 removed this item isn’t relevant to the
standard and goes beyond the purpose of this standard. We understand that this is
included for curtailment of load during emergency conditions (EOP001 Attach 1) but
feel it is unnecessary in planning.

Response: The SDT agrees and item 8 of Section II has been modified accordingly.
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent Transmission Planners and Planning
Coordinators
The SDT believes assessment of the impact of Firm Demand interruption to the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community
Salt River Project
BrightSource Energy, Inc.

No

We disagree with the inclusion of the information in Section II.2.a (the estimated
number and type of customers affected) and II.2.b (An assessment of the use of Firm
Demand interruption under footnote ‘b’ on the health, safety, and welfare of the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

54

Organization

Yes or No

Question 3 Comment

Los Angrles Department of
Water and Power

community). We suggest removing them. Section II.2.a is an administrative process
and not needed for reliability of the Bulk Power System.

Deseret Generation &
Transmission Cooperative

Section II.2.b is vague and can be interpreted numerous ways, which make
compliance difficult. It can also become a legal liability issue for the service provider,
even if that loss of load is judged to be a prudent decision by the “applicable
regulatory authorities or governing bodies responsible for retail electric service
issues”.

Tri-State Generation &
Transmission Association, Inc.
California Independent
System Operator
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation Districtt
Utility System Efficiencies, Inc.

Response: The SDT believes that the provision of customers affected and the duration and assessment of the impact of Firm
Demand interruption on the health, safety, and welfare of the community is not solely administrative and is necessary for
understanding the reliability impact and for stakeholders to make an informed decision.
Based on comments received, the wording has been changed to clarify the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
MRO NSRF

No

American Transmission
Company

Order 890 already requires Transmission Planners to solicit the input of affected
stakeholders on TPL standards. Order 890 does not provide prescriptive details
regarding the information that should be included in the stakeholder process for the
TPL standards, which includes footnote ‘b’. Stakeholders that participate in
stakeholder meeting can ask for any information that they want regarding the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

55

Organization

Yes or No

Question 3 Comment
proposed use of Firm Demand interruption. They do not need a third party to
prescribe what information they need or want. So, the NSRF suggests that Section II
be removed.
If Section II is not removed, then the NSRF suggests that at least Items 2b, 6, and 8 be
removed from the listing. o Item 2b - The scope and content expectation for an
assessment of the potential impact of the proposed Firm Demand interruption on the
health, safety, and welfare of the community is basically broad, nebulous, and vague.
The stakeholders would raise any specific, relevant questions or concerns in these
areas if they exist without a prescriptive stipulation for this information in the TPL002 standard.
o Item 6 - The verification of that the TPL performance requirements will be met by
the use of Firm Demand interruption is superfluous. Proposal to use Firm Demand
interruption to meet the TPL-002 performance requirements would always be the
result of identifying (i.e. verifying) what Firm Demand interruption is needed to meet
the TPL-002 performance requirements.
o Item 8 - Potential overlapping uses of footnot ‘b’ with adjacent planners will not
always exist and would probably be rare. In addition, whenever the situation would
exist, then any applicable adjacent planners would be affected stakeholders and
would have the opportunity to attend the stakeholder meeting and raise any
questions or concerns in that meeting without the stipulation of this information in
the TPL-002 standard.

Response: Order 890 is not applicable to all NERC regions and is not a standard. No change made.
The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

56

Organization

Yes or No

Question 3 Comment

The SDT believes the wording regarding the TPL standards is necessary to ensure the focus on meeting the TPL standard’s reliability
requirements is not lost and that the end state following interruption of Firm Demand meets those requirements. No change made.
The SDT believes application of a wide area view to the use of Firm Demand interruption is necessary to avoid reliability issues that
would not be seen by an individual Transmission Planner or Planning Coordinator. There is no standard requirement for adjacent
Transmission Planner/Planning Coordinator’s to participate in Order 890 type processes therefore it must be addressed. No change
made.
SERC EC Planning Standards
Subcommittee

No

We recommend using a technical basis for load shedding instead of a Stakeholder
Process.

Southern Company

No

Southern recommends using a technical basis for load shedding instead of a
Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the
original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission
Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided
that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague,
unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a Stakeholder Process, but because they wanted the process better defined including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
ACES Power Member
Standards Collaborators

No

(1) We disagree with with including the Facilities that will exceed their rating and the
applicable contingenices. We think this information should be treated as
confidential. It could be used by bad actors to create outages within communities.
The risk to the Bulk Electric System is higher than the benefit of sharing this
information.
(2) We disagree that the Transmission Planner should be required to provide an
assessment on the health, safety and welfare of the community. First, the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

57

Organization

Yes or No

Question 3 Comment
stakeholders will have an opportunity to provide this information through either the
Transmission Planner’s stakeholder comment process or through the local regulatory
agency’s stakeholder comment process. Second, these planned interruptions in firm
demand are expected to be short in nature so the impacts should be minimal. Third,
an assessment on the health, safety and welfare of the community is an unnecessary
burden on the utility and is better suited for local governments. Even if the utility
should perform such an assessment, health, safety and welfare are ambiguous terms
without clear parameters or expectations for the data. Does this mean that the
Transmission Planner verifies police stations, fire departments, hospitals and other
critical public support agencies are not included in the planned load shed? Most
electric providers already do this when developing load shed plans and are likely not
going to includes such customers in any load shed plan. Fourth, communities already
have plans in place for the interruption of electricity so as long a critical customers
are not shed, then the impacts are likely economic in nature.
(3) Bullet 3 needs to be clarified that it is not an estimated frequency but rather a
historical frequency. How do you estimate a frequency for a new planned load shed?
It also needs to be clarified if the historical frequency is all instances within the
Transmision Planner’s area or just the specific location of the planned load shed. If it
is all instances, it further needs to be clarified that it is only within its own TP area.
(4) We do not believe that expected duration of the planned load shed should be
required. Any duration will likely be a guess. When actual contingencies occur, the
time of restoration varies. Consider the recent event in Arizona and Southern
California. The report indicated that the TOP thought they could return the 500 kV
line that initiated the event in a few minutes. They were unaware that the phase
angle was too large to close. The expected duration is too speculative and should not
be required.
(5) We disagree with the need to include future plans to mitigate the planned load
shed in all cases. For remote areas of the system, there simply may not be sufficient
load growth to justify any other mitigation.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

58

Organization

Yes or No

Question 3 Comment
(6) Item 8 should be clarified that it applies only to the Planning Coordinator. The
Planning Coordinator should coordinate all of its Transmission Planner’s Planning
Assessments. This would include evaluating planned load shedding.

Response: 1) The use of Firm Demand interruption and events involved should only affect local area issues and should not create
issues for the BES that could be exploited by “bad actors.” No change made.
2) The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent. As stated, it is something that TP/PC’s normally do.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3) Any estimate of future performance has to be based on some sort of available historical information, even for a new line/delivery.
The SDT believes it is clear that for stakeholders to make an educated decision regarding Firm Demand interruption, the information
must be provided for each instance of Firm Demand interruption use within the Transmission Planner/Planning Coordinator’s area.
No change made.
4) The SDT believes stakeholders need an expectation of the duration in order to evaluate the impact. No change made.
5) Possible future plans could include a decision not to mitigate the need for Firm Demand interruption. No change made.
6) The standard does not dictate who performs the assessment, only that one be performed. No change made.
Bonneville Power
Administration

No

BPA does not support including information under Sections II.2.a and II.2.b, estimated
number and type of customers affected, or an assessment of the use of Firm Demand
interruption on the health, safety, and welfare of the community as this information
does not support reliability of the BES. If footnote b were applied, reliability of the
BES is actually assessed by meeting the applicable TPL Standard for a single
contingency with loss of load regardless of the type of customers or use of Firm
Demand.

Response: The information is necessary to make an informed judgment and assessment, with stakeholder input, as to whether

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

59

Organization

Yes or No

Question 3 Comment

reliability of the BES will be maintained. Evaluation of the consequences of an event is a part of assessing reliability. No change
made.
The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
TVA Transmission Reliability
Engineering & Controls

No

Under Item #2 - TVA is not sure how to properly address “health, safety, and welfare
of the community” from an regulatory standpoint. Please clarify what this would
require - such as number of hospitals without emergency backup, etc?
Also please see answer to question #1 - TVA beleives that only larger load drops
should require a Stakeholder review.

Response: The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the
community is necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on
comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
See response to Q1.
MISO

No

Again, this Section is overly prescriptive. This Section needs only to stipulate at a high
level, the kind of information needed to support the proposed utilization of the
footnote, leaving much of the detail to the application process overseen by the
Regional Entities (given the RE will eventually need to review and assess the reliability
impact of such utilization). We suggest the SDT to reduce this Section, or remove this
altogether with appropriate insertion into Section I that address a general need for
supporting information to be specified by the RE’s review process.

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Independent Electricity
System Operator

Yes or No

Question 3 Comment

No

Again, this Section is overly prescriptive. This Section needs only to stipulate at a high
level, the kind of information needed to support the proposed utilization of the
footnote, leaving much of the detail to the application process overseen by the
applicable reliability authority to review and assess the reliability impact of such
utilization. We suggest the SDT to reduce this Section, or remove this altogether with
appropriate insertion into Section I that address a general need for supporting
information to be specified by the RA’s review process. Also note that use of a
“stakeholder process”, as per FERC’s concerns, must be crisp and clear.

Response: The SDT believes the information required provides what is necessary for a high-level assessment of the impact of
utilizing Firm Demand interruption and is necessary for stakeholders to make an informed decision. No change made.
Public Utility District No. 1 of
Snohomish County

No

San Diego Gas & Electric

No

We don’t support the addition of stakeholder process language.

Response: Without specific comments, the SDT is unable to respond.
Tacoma Power

No

Item II.2.b Since this is a stakeholder process, each stakeholder can make an
assessment for themselves about the effect of Firm Demand interruption on the
health, safety and welfare of the community. This requirement is too vague to be
enforceable.
Item II.5 Particularly in the case of P2.1 contingencies, utilities may not have any
plans to eliminate load shedding “at the fringes of various systems” as the FERC
NOPR noted would be acceptable.

Response: Stakeholders would not be likely to have all the information required to make an informed decision. The SDT is seeking
the appropriate balance between being too vague and too prescriptive. Based on comments received, the wording has been clarified
to better show the SDT’s intent.

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Yes or No

Question 3 Comment

2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
There is a requirement to include any mitigation plans, not a requirement to mitigate – doing nothing could be a possible plan. No
change made.
Manitoba Hydro

No

1 a. It would be very difficult to estimate the annual hours of exposure at or above a
certain load level.
2 b. An assessment on the health, safety, and welfare of the community should not
be part of a reliability assessment - this is purely subjective.
3 & 4. In situations where load interruption is a new proposal, historical data will not
be available. What does the SDT expect here?
5. Is there a requirement to mitigate? If there is a requirement to mitigate, the
required time frame is not identified.

Response: 1) Planning studies should provide the information necessary as to the Load levels at which the use of Firm Demand
interruption would be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the
duration. No change made.
2) The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3 & 4) Any estimate of future performance has to be based on some sort of available historical information. Use of similarly situated
lines/deliveries allows for estimation of future performance.
5) There is a requirement to include any mitigation plans, not a requirement to mitigate – doing nothing could be a possible plan.
Ameren

No

We request that Items 5 and 7 also include information regarding estimated costs
and schedule for implementation. Any permitting issues associated with the

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Yes or No

Question 3 Comment
alternatives should also be included. Any previous attempts to build facilities but
were blocked should also be part of the record.

Response: Items 5 and 7 do not prohibit inclusion of cost, schedule information, or other project information and it is anticipated
these issues would normally be included. The SDT is seeking the appropriate balance between being too vague and too prescriptive.
No change made.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Salt River Project

No

Additional comment from SRP for Q #5.

Response: Please see response to Q5.
City of Austin dba Austin
Energy

No

Some of the information for inclusion in the Stakeholder Process is too burdensome
and of limited value. In particular, 2b and 4 can be deleted because the requested
information may not be available -- particularly if it is new load growth.

Response: The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the
community is necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on
comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Any estimate of future performance has to be based on some sort of available historical information. Use of similarly situated
lines/deliveries allows for estimation of future performance. No change made.
LCRA Transmission Services
Corporation

No

Requirement 1 only requires that the Transmission Planner provide system load data,
however, assumptions about system dispatch are also relevant. Requiring load
without dispatch will not provide a complete understanding of the conditions under
which Footnote 12 will apply. As a reliability standard, the Transmission Planner is
required to find a range of plausible system conditions under which a criteria

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Yes or No

Question 3 Comment
violation may be resolved.
The requirement (1a) to provide an estimate of the exposure creates an overly
burdensome requirement to investigate a wider range of possible operating
conditions than is currently performed.
Requirement 2a and 2b are overly burdensome on at Transmission
Planner/Transmission Owner who does not directly serve retail loads by placing a
requirement on the Transmission Planner/Transmission Owner to provide data that is
outside of its control to develop or maintain.

Response: The SDT believes the information in Section II is sufficient and would bring out any concerns related to dispatch
conditions. No change made.
Planning studies should provide the information necessary for 1.a as to the load levels at which the use of Firm Demand interruption
would be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the duration.
The SDT believes 2.a and 2.b’s provision of customers affected and duration and assessment of the impact of Firm Demand
interruption on the health, safety, and welfare of the community is necessary for understanding the reliability impact and for
stakeholders to make an informed decision. Based on comments received, the wording for 2.b has been clarified to better show the
SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Duke Energy

No

In Item #8, replace the word “planners” with the words “Transmission Planners”.

Response: The SDT agrees, and item 8 of Section II has been modified accordingly.
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent Transmission Planners and Planning
Coordinators
Hydro-Quebec TransEnergie

No

For example, under 2 b., assessment of the impacts of interruptions on health, safety,
or welfare of the community is not information that could be reasonably expected to
be available to system planners. All loads may face interruptions from time to time,

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Yes or No

Question 3 Comment
and the impact on health, safety or welfare is very difficult to identify. This item
should be deleted.

Georgia Transmission
Corporation

No

GTC does not understand how item #2b of Section II pertains to the Transmission
Planner or the Planning Coordinator. These types of assessments are beyond the
scope of the Transmission Planner or the Planning Coordinator and if necessary,
should possibly be done by the Load Serving Entity.GTC Recommends the SDT
remove item #2b, the following sentence:”An assessment of the use of Firm Demand
interruption under footnote 12 on the health, safety, and welfare of the community.”

Response: Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. A
similar requirement for the Transmission Planner/Planning Coordinator would rely on the same type of information and sources
already required under the EOP standard. The SDT believes assessment of the impact of Firm Demand interruption on the health,
safety, and welfare of the community is necessary for understanding the reliability impact and for stakeholders to make an informed
decision. Based on comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
NorthWestern Energy
(NWMT)

No

Comments: The estimated number and type of customers affected is not needed for
reliability of the Bulk Power System. We suggest removing Item 2a in Section II of
Attachment 1.
An assessment of the health, safety, and welfare of the community should not be
required. It is too vague and coud present legal problems. We suggest removing
Item 2b in Section II of Attachment 1.

Response: The SDT believes provision of customers affected and duration and assessment of the impact of Firm Demand
interruption on the health, safety, and welfare of the community is necessary for understanding the reliability impact and for
stakeholders to make an informed decision.
Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. The SDT believes
assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for
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Yes or No

Question 3 Comment

understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received, the wording
has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
ISO New England Inc.

No

Section II, Paragraph 2b requires “an assessment of the use of Firm Demand
interruption under footnote 12 on the health, safety, and welfare of the community”.
A great deal of subjectivity and information that is not readily available to the
Transmission Planner or Planning Coordinator would be required to accurately
access the effect of load shedding on the community as required by 2b.
Additionally Paragraphs II.3 and 4 require estimates of the frequency and duration of
Firm Demand interruption would be difficult to provide. These requirements should
be deleted. These requirements also undermine the deterministic nature of the
Planning Standard.
Paragraph II.2.5 that requires future plans to mitigate the need for Firm Demand
Interruption should be modified to again emphasize the near term nature of single
contingency non-consequential load shedding as a Planning option.

Response: Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. A
similar requirement for the Transmission Planner/Planning Coordinator would rely on the same type of information and sources
already required under the EOP standard. The SDT believes assessment of the impact of Firm Demand interruption on the health,
safety, and welfare of the community is necessary for understanding the reliability impact and for stakeholders to make an informed
decision. Based on comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Planning studies should provide the information necessary as to the Load levels at which the use of Firm Demand interruption would
be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the duration. Any
estimate of future performance has to be based on some sort of available historical information. Use of similarly situated

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Yes or No

Question 3 Comment

lines/deliveries allows for estimation of future performance. No change made.
A purpose of the stakeholder process is to ensure those impacted by use of Firm Demand interruption and the regulators responsible
for quality of service have input on its use and the acceptability of the mitigation plan. No additional elaboration on the use of Firm
Demand interruption in the standard is necessary. No change made.
South Carolina Electric and
Gas

No

See response to question #1

Response: Please see response to Q1.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT’s response to question 1 - the NERC Reliability Standards should
not contain requirements related to stakeholder processes, whether they are
procedural or substantive. If an exception process is retained, it should be outside of
the NERC Reliability Standards (e.g. in the Rules of Procedure).
ERCOT also provides the following comments on Section II - the ERCOT comments are
in parentheses for easy reference and distinction relative to the proposed
requirements. II. Information for Inclusion in Item #3 of the Stakeholder ProcessThe
responsible entity shall document the planned use of Firm Demand interruption
under footnote ‘b’ which must include the following: - (ERCOT COMMENT: This is all
that is needed for this. The documentation would be relative to the objective criteria
developed for this purpose.)
1. Conditions under which Firm Demand interruption under footnote ‘b’ would be
necessary:a. System Load level and estimated annual hours of exposure at or above
that Load levelb. Applicable Contingencies and the Facilities outside their applicable
rating due to that Contingency(ERCOT COMMENT: “1” is not necessary if objective
criteria are developed as benchmarks for the exception process. In that case,
exceptions would only be allowed if the objective criteria were met, regardless of the
underlying assumptions related to conditions and contingencies.)
2. Amount of Firm Demand MW to be interrupted with:a. The estimated number and

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Yes or No

Question 3 Comment
type of customers affectedb. An assessment of the use of Firm Demand interruption
under footnote ‘b’ on the health, safety, and welfare of the community(ERCOT
COMMENT: The considerations reflected in a and b are inappropriate for a reliability
standard. Appropriate considerations for reliability standards are related to the
reliability performance of the system. The considerations in a and b are more akin to
quality of service issues better suited for regional policy discussions. It is not within
the purview of the SDT to address those matters.)
3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on
historical performance(ERCOT COMMENT: Historical performance is irrelevant. If the
SDT is going to retain revisions that accommodate non-consequential load shedding,
then the only relevant metrics are the objective criteria that set the benchmarks for
such exceptions.)
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on
historical performance(ERCOT COMMENT: See ERCOT response to “3” above.)
5. Future plans to mitigate the need for Firm Demand interruption under footnote
‘b’(ERCOT COMMENT: This is redundant to the requirement in the reliability
standards that requires a plan to resolve any violations identified in the planning
process. Furthermore, if load shedding is allowed, this requirement doesn’t make
sense. Presumably the idea behind allowing these exceptions is to obviate the
prospective need for other alternatives. If that is not the case, then there is no need
to allow the exceptions, because the transmission upgrades to mitigate the need for
load shedding can be established in the planning horizon.)
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’(ERCOT COMMENT: The basis for the load
shedding exception is to provide a means to meet the TPL performance requirements
in the context of a planning assessment. Accordingly, this is redundant to the
planning assessments, the point of whichis to identify and resolve performance
issues.)

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Yes or No

Question 3 Comment
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote ‘b’(ERCOT COMMENT: Load shedding
exceptions should be based on objective criteria and be reviewed pursuant to a
process external to the NERC reliability standards. Alternative discussions could be
part of that external process.)
8. Assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners(ERCOT COMMENT: It is not clear what this means. Each functional entity
performs assessments relative to its own system. This appears to introduce a vague
regional transmission planning requirement with no structure or rules for such
assessments.)

Response: Please see response to Q1.
1. The SDT believes the information in Section II is necessary for stakeholders to understand the reason Firm Demand interruption
use is appropriate and make an informed decision. No change made.
2. The SDT believes the information in section II is necessary for stakeholders to understand the reason Firm Demand interruption
use is appropriate and make an informed decision. The SDT believes provision of customers affected and duration and assessment of
the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for understanding the
reliability impact and for stakeholders to make an informed decision. Based on comments received, the wording for 2.b has been
clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3. and 4. The SDT believes the information in Section II is necessary for stakeholders to understand the reason Firm Demand
interruption use is appropriate and make an informed decision. Any estimate of future performance has to be based on some sort of
available historical information even for a new line/delivery. The SDT believes it is clear that for stakeholders to make an educated
decision regarding Firm Demand interruption, the information must be provided for each instance of Firm Demand interruption use
within the Transmission Planner/Planning Coordinator’s area. No change made.
5. The mitigation plan identifies how reliability violations will be avoided in the future where projects or other actions are not
available in time or are not cost effective. No change made.

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Yes or No

Question 3 Comment

6. The SDT believes the wording regarding the TPL standards is necessary to ensure the focus on meeting the TPL standard’s
reliability requirements is not lost and that the end state following interruption of Firm Demand meets those requirements. No
change made.
7. Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning
Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that
the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable,
and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal
as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not
because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of quantitative
and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft
added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to
move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
8. The SDT believes application of a wide area view to the use of Firm Demand interruption is necessary to avoid reliability issues that
would not be seen by an individual Transmission Planner/Planning Coordinator. The SDT believes assessment for Adverse Reliability
Impacts is an appropriate step. However, the SDT has moved this responsibility to the ERO and deleted the Regional Entity from any
involvement.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Orlando Utilities Commission

Yes

Data element 5 should probably read. "List any Future Plans or future system changes
to mitigate the need for Firm Demand Interruption under footnote 'b'". There can be
cases where there is no planned future project to relive the problem, or it could be
expected that load will go down or changes on neighboring systems will relieve the
problem.

Response: Possible future plans could include a decision not to mitigate the need for Firm Demand interruption. No change made.

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Yes or No

LCEC (Lee County Electric
Cooperative

Question 3 Comment
No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

Arizona Public Service
Company

Yes

CPS Energy

Yes

Essential Power, LLC

Yes

American Electric Power

Yes

Lincoln Electric System

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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4.

Do you agree with the Instances for which Approval of Interruptions is required in Section III of Attachment I? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: The 25 MW threshold for requiring regulatory authority review was questioned by several entities. The
original 25 MW threshold came from the Registry Criteria for Load-Serving Entities. The data request showed that the average value of
footnote ‘b’ utilization was approximately 19 MW. Therefore, the SDT has decided to leave the process threshold at 25 MW.
Several entities questioned having the 300 kV threshold for Contingencies because it has no material impact to Load and that the
threshold should be based on a MW amount only. The SDT believes that the 300 kV threshold is appropriate, as the proposed TPL-0012, which was accepted by industry and the NERC Board of Trustees, made a distinction between HV and EHV and the handling of
Contingencies based on the 300 kV level. The SDT believes that the establishment of this threshold within footnote ‘b’ is consistent with
that approach and places the proper emphasis on EHV.
Several entities had concerns that actions from a regulatory body won’t happen quickly enough and that such a requirement was not
appropriate for a reliability standard. There were also concerns voiced about inconsistencies in such an approach. The SDT understands
these concerns and has clarified the language to assist in alleviating such concerns. The SDT also advises any entity wishing to utilize
footnote ‘b’ in its planning process to start that process at an appropriate time so that it can be completed by the needed date.
Some concerns were raised about the role of the Regional Entity in this process. After reviewing the submitted comments, the SDT
agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now placed on
NERC as the ERO. This change should help to promote continent-wide consistency.
The following changes were made due to industry comments:
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the
applicable regulatory authority or governing body responsible for retail electric service issues does not object to the use of Firm Demand
interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.
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Southwest Power Pool
Reliability Standards
Development Team

Yes or No

Question 4 Comment

No

Need clarification around why the 25MWs threshold on generation was thrown into
load interruption topic. Looking at the registry criteria for generation the threshold
should be 20Mws for a single unit and 75 MWs for aggregated units. Not sure where
the 25MWs threshold came from for generation. The 25 MW threshold in Section III
is duplicative of the registration limit for generation in the ERO Statement of
Compliance Registry Criteria. It is submitted for comment at this time but will not be
finalized until after the above mentioned data request is complete and the final value
will be submitted for industry comment and approval in the next posting. The GOP
registration criteria is 20MWs. Whereas the registration criteria for LSEs and DPs is
25MWs. There appears to be some co mingling of criteria. Additionally this raises
the question of whether x =25MWs. Please clarify which you intended to use.
We are concerned that getting retail service regulatory authority approval in a quick
manner could be difficult. We are also concerned that if it does get caught in the
process of being approved and there is no time to construct, that we would not want
to be found out of compliance due to something that is out of our control.

Response: The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and
Operators. The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the
process threshold at 25 MW. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than
75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’
utilization at 75 MW.
The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some of
the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will be
completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
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Salt River Project

Yes or No

Question 4 Comment

No

While we do agree with the intent, it is over-reaching for a NERC Standard to require
action from the applicable regulatory authority or governing body responsible for
retail electric service issues to give approval of the use of Firm Demand interruption
under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.
MRO NSRF

No

The NSRF suggests that Section III be removed for the following reasons.
o The types of transmission projects that would be needed to avoid proposing the
use of the Firm Demand interruption under footnote ‘b’ are expected to be high cost,
long lead time Corrective Action projects. Therefore, consideration of the any
necessary approvals from regulatory authorities or governing bodies responsible for
approving the Corrective Action project is a prerequisite and essential to any
discussion or stiputlations regarding disapproval of the use of footnote ‘b’ proposal.
The proposed TPL-002 text for Section III does not include any language to address
this crucial aspect of any footnote ‘b’ approval sipulations.
o The diversity of applicable regulatory authorities and governing bodies, as well as
their justicitional scope or criteria with respect to the approval of interrupt retail
electic service (as well as transmission Corrective Action projects), are too diverse
and complex to be appropriately addressed by proposed Approval stipulations in the

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Yes or No

Question 4 Comment
TPL-002 standard.
If Section III is not removed, then the NSRF suggests the following changes.
o Include the subject of approvals of Corrective Action projects that are necessary to
negate the need for approval of the proposed Firm Demand interruption.
o Replace the criteria regarding the voltage level of the relevant Contingency with
criteria regarding the amount and type of Firm Demand that would be subject to
interruption. The voltage level of the applicable Contingency elements are not
material to impact on the affected load.
o Replace the applicable amount of Firm Demand interruption criteria from 25 MW
to at least 100 MW. There are many radial fed loads that are much geater that 25
MW and there are no stackholder meetings and required approvals for allowing the
loads to be fedd radially (subject to interruption for Category B contingencies) rather
than being network fed. The DOE threshold for requiring formal system event
analysis is 100 MW of load dropping. So, why should the TPL-002 standard required
special approvals to allow less than 100 MW of load be subject to interruption to
assure BES reliability?
o Change the text of “in Year One of the Planning Assessment” to “in the ten year
planning horizon of the Plannign Assessment”. The planning assessments may reveal
that the need to use of Firm Demand interruption will occur in Year 2, Year 3 or
beyond (e.g. when a significant previously unforecast load increase is forecast to
occur before any needed Corrective Action project could be initiated and
implemented).
o The NSRF is concerned that the current wording, “Corrective Action in Year One of
the Planning Assessment” could be interpreted to require an annual stakeholder
process review and approval. The NSRF suggests that the standard drafting team
provide some language regarding a specific period that is expected for reaffiming the
approval of the Firm Demand interruption. A review interval of at least every five
years should provide reasonable business certainty and allow for future transmission

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construction if needed. The specific defined period of review should allow entities to
operate in an effective manner.
The NSRF is also concerned about the condition where approval was granted and
then removed. Would an entity be instantly non-compliant to the TPL standards? If
this is a possibility, the Standard Drafting Team should add a grace period that allows
an entity to credibly construct a project to remain compliant.

American Transmission
Company

No

ATC recommends that Section III be removed for the following reasons.
o The types of transmission projects that would be needed to avoid proposing the
use of the Firm Demand interruption under footnote ‘b’ are expected to be high cost,
long lead time Corrective Action projects. Therefore, consideration of the any
necessary approvals from regulatory authorities or governing bodies responsible for
approving the Corrective Action project is a prerequisite and essential to any
discussion or stipulations regarding disapproval of the use of footnote ‘b’ proposal.
The proposed TPL-002 text for Section III does not include any language to address
this crucial aspect of any footnote ‘b’ approval stipulations.
o The diversity of applicable regulatory authorities and governing bodies, as well as
their jurisdictional scope or criteria with respect to the approval of interrupt retail
electric service (as well as transmission Corrective Action projects), are too diverse
and complex to be appropriately addressed by proposed approval stipulations in the
TPL-002 standard. If Section III is not removed, then ATC recommends the following
changes.
o Include the subject of approvals of Corrective Action projects that are
necessary to negate the need for approval of the proposed Firm Demand
interruption.
o Replace the criteria regarding the voltage level of the relevant Contingency
with criteria regarding the amount and type of Firm Demand that would be
subject to interruption. The voltage level of the applicable Contingency elements

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Question 4 Comment
are not material to impact on the affected load.
o Replace the applicable amount of Firm Demand interruption criteria from 25
MW to at least 100 MW. There are many radially fed loads that are much greater
than 25 MW and there are no stakeholder meetings or required approvals for
allowing the loads to be fed radially. The DOE threshold for requiring formal
system event analysis is 100 MW. So, ATC believes the TPL-002 standard should
not require special approvals to allow less than 100 MW of load to be
interrupted to assure BES reliability. o Change the text of “in Year One of the
Planning Assessment” to “in the ten year planning horizon of the Planning
Assessment”. The planning assessments may reveal that the need to use of Firm
Demand interruption will occur in Year 2, Year 3 or beyond (e.g. when a
significant previously unexpected load increase is forecast to occur before any
needed Corrective Action project could be initiated and implemented).
o ATC is concerned that the current wording, “Corrective Action in Year One of the
Planning Assessment” could be interpreted to require an annual stakeholder process
review and approval. ATC suggests that the standard drafting team provide some
language regarding a specific period that is expected for reaffirming the approval of
the Firm Demand interruption. A review interval of at least every five years should
provide reasonable business certainty and allow for future transmission construction
if needed. The specific defined period of review should allow entities to operate in
an effective manner.

Response: If you have already gotten approval from regulatory bodies in your planning process, then Section III is basically already
accomplished, and carrying out the remaining details should not be burdensome. No change made.
While it may be true that regulatory authorities and governing bodies are diverse and complex, they are representing their area of
responsibility. What may be acceptable in one area, may not be acceptable in another. This is determined by the appropriate
authorities. No change made.
The SDT does not believe approvals from regulatory authorities or governing bodies responsible for approving the Corrective Action
project is a prerequisite or essential. The focus of this portion of the standard is dropping Load and when approval is necessary.
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Question 4 Comment

There is no benefit in including approval of Corrective Actions. No change made.
The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the Contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers, and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load dropping, it should
require approval. No change made.
The data request also showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. No change made
The text regarding Year One of the Planning Assessment just means that approval from the appropriate regulatory bodies is needed
at least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be determined in
the study of a future year or that approval cannot be sought sooner.
The intent of the SDT was that a review must be obtained one time from the appropriate regulatory body. It does not need to be
reviewed again unless the situation changes. The SDT has changed the wording to the following:
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
The proposed TPL-001-2 accommodates this concern regarding circumstances beyond the control of the Transmission Planner or
Planning Coordinator in Part 2.7.3 of Requirement R2.
SERC EC Planning Standards
Subcommittee

No

We recommend using a technical basis for load shedding instead of a Stakeholder
Process. However, if a Stakeholder Process is used, the approval thresholds are
correct. The Stakeholder Process should not even be initiated for less than these
threshold levels.

Southern Company

No

Southern recommends using a technical basis for load shedding instead of a
Stakeholder Process. However, if a Stakeholder Process is used, the approval
thresholds given in the draft seem appropriate. Furthermore, we believe the
Stakeholder Process should not even be initiated for less than these threshold levels.

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Question 4 Comment
Lower amounts of load and lower voltage contingencies do not need to be taken
through a Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
ACES Power Member
Standards Collaborators

No

(1) What is the justification for selecting a 300 kV contingency as a threshold for
requiring local regulatory agency approval? What if the planned load shed is only for
1 MW? If a threshold is required, we think it should be based on load size rather than
contingency size?
(2) What is the justification for selecting 25 MW of planned firm load interruption as
a threshold for requiring local regulatory approval? The threshold could be set based
off of the accompanying Section 1600 data request. Since there are likely not many
instances, it could be required for any new instance that exceeds the existing planned
load shed amounts. Thus, the threshold would be set just above existing planned
load interruptions.
(3) A disclaimer should be added to clarify that an entity may still have to seek local
regulatory agency approval per the local regulatory agency’s rules. Nothing in the
NERC standard will change the local regulatory agency’s rules.
(4) What if the local regulatory agency does not want to address the planned load

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Question 4 Comment
shed in the planning time frame? What is the Transmision Planner required to do?
While it is likely a local regulatory agency would be interested in addressing a
planned load interruption, nothing in the NERC or Commission rules can compel a
local regulatory agency to address such matters in a specific time frame.
(5) Bullet 1.a is confusing. Is it intended to say that if two Elements are part of a
contingency and the Elements have different voltage classes, the Element with the
lowest voltage class must exceed the 300 kV threshold? If this is the case, the bullet
needs further clarification because it does not state this clearly.
(6) The first paragraph after section III appears to contradict bullets 1 and 2. Bullets
1 and 2 place contingency and load thresholds on the planned firm load interruption.
However, this paragraph says that the regulatoy body responsible for retail electric
service must approve the planned load shed before it can be used in Year One of the
planning assessment. If the purpose is for the thresholds to apply beyond Year One
and any instance in Year One to require approval, then the language regarding the
thresholds needs to clarify that the thresholds apply beyond Year One only.
(7) We think it is redundant for the Regional Entity to evaluate planned interruptions
of firm load in its footprint. The Planning Coordinator has a wide area view and is
already required to do this for its footprint. The Planning Coordinator already works
with its neighbors to evaluate impacts. Requiring this evaluation by the Regional
Entities is arbitrarily based on historical and political boundaries. Many Planning
Coordinators have views that are broader than the Regional Entity view because they
are in multiple regions. If this evaluation will be required on a regional basis, why
won’t it be required on an interconnection?
(8) The evaluation required by the Regional Entity may be completed before planned
load interruption is approved by local regulatory body. The TP and PC must submit
the data based on their plan before the local regulatory body approves the planned
load interruption. The Regional Entity must complete its evaluation within 45 days of
receiving the information. There is no obligation for the local regulatory body to act
within 45 days. Wouldn’t it make more sense to evaluate the planned load shed after

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Question 4 Comment
it is approved by the local regulatory body?

Response: (1) The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the
Contingency studied. This is based on the belief that Transmission lines 300 kV and above are for bulk power transfers, and lower
voltage lines are more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load shed,
it should require approval even if it is only 1 MW.
(2) The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. No change made.
(3) There is no need for such a disclaimer in a NERC Standard. An entity has to abide by other applicable rules outside of the
standard. No change made.
(4) The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some
of the concerns. If the local regulatory agency does not want to address the planned Load shed, then they are giving their tacit
approval to the Load shedding.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
(5) Yes. For 1.a to apply, the Element with the lowest system voltage level must be 300 kV or above. The SDT believes the wording is
clear. No change made.
(6) The text regarding Year One of the Planning Assessment just means that approval from the appropriate regulatory bodies is
needed at least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be
determined in the study of a future year or that approval cannot be sought sooner.
(7) The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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

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Question 4 Comment

whether there are any Adverse Reliability Impacts caused by the request to utilize footnote ‘b’ for Firm Demand interruption.
(8) No. The planned Load shed should not be reviewed by the local regulatory body unless it has been determined that there are no
Adverse Reliability Impacts.
Bonneville Power
Administration

No

Regarding Section III.2 as stated above, BPA does not support quantitative limits on
planned interruption, as planners generally do not plan the system to interrupt
demand for a single contingency. Setting a quantitative limit would push
transmission planners to plan the system to meet such a limit for a single contingency
in all cases.

Response: The SDT does not agree that setting a quantitative limit would push Transmission Planners to plan the system to meet
such a limit for a single Contingency in all cases. The footnote states that an objective of the planning process should be to minimize
the likelihood and magnitude of Load shed. However, a quantitative limit is needed to ensure that unreasonable amounts of Load
shed are not proposed. No change made.
TVA Transmission Reliability
Engineering & Controls

No

Please see answer to question #1. TVA believes that the requirements of 25 MW as
well as any Bulk contingency over 300-kV is much too burdensome. TVA beleives that
only larger load drops should require a Stakeholder review.

Response: Please see response to Q1.
Arizona Public Service
Company

No

AZPS does not agree that approval by the Regional Entity should be required. Once
the process has been fully vetted by the stakeholders, including the regulatory
authority for retail service, there is absolutely no need for Regional Entity approval.
There would be no adverse affect of non-consequential load tripping on the BES. No
reason for Reginal Entity involvement.

Response: The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order,
is now placed on NERC as the ERO. This change should help to promote continent-wide consistency.

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Question 4 Comment

Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
BrightSource Energy, Inc.
Los Angrles Department of
Water and Power
Deseret Generation &
Transmission Cooperative
California Independent
System Operator
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation Districtt
Utility System Efficiencies, Inc.

No

While we do not disagree with the intent, it is over-reaching for a NERC Standard to
require action from the applicable regulatory authority or governing body responsible
for retail electric service issues to approval of the use of Firm Demand interruption
under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.
Requiring the Regional Entity to approve the Non-Consequential Load Loss under
footnote b in TPL-002 (Footnote 12 in TPL-001-3) is duplicative and would increase
the work load of the Regional Entities without improving reliability. The TP and PC
are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the
application of footnote ‘b’ (see Section II.6) and the assessment of potential
overlapping uses of footnote ‘b’ with adjacent planners” (see Section II.8), it is hard
to imagine what type of review and verification is required to show that “there are
no Adverse Reliability Impacts including any potential cumulative effect within the
Regional Entity’s footprint”.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.

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Question 4 Comment

The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
MISO

No

We generally agree with the instances for which approval or interruptions is required,
but do not agree with the requirement to seek regulatory approval.In general, when
the footnote is proposed to be utilized as an interim measure until transmission
facilities can be added or reinforced, regulatory approval must be sought in advance.
Having this requirement in a reliability standard not only is unnecessary, but also
introduces regulatory requirements (which provides no reliability benefit or basis) in
a reliability standard. NERC reliability standards should focus only on BES reliability,
not any regulatory requirements. Section III should therefore stipulate a high-level
requirement for the proposing entity to submit the proposal to the RE for review and
concurrence. Along with the submission, the RE may require the proponent to
include a copy of appropriate regulatory approval (which the entity should have
already obtained). The conditions (1) and (2) for seeking regulatory approval can be
retained, but now become the criteria for seeking review and concurrence by the RE.
Additionally, Attachment 1 requires that the ERO develop a methodology on
evaluation criteria to be published for determining Adverse Reliability Impacts for
approval by the ERO. Planning Assessments are performed on an annual basis. The
Attachment 1 process and ERO methodology may require a lengthy approval process
that must be repeated on an annual basis.

Response: The SDT has modified the footnote to require regulatory authority review rather than approval. This should help alleviate
some of the concerns.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
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Question 4 Comment

or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual assessment if the
process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the parameters have not
changed. If any changes have occurred to the original parameters, these issues must then be addressed in the Stakeholder Process
before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
Essential Power, LLC

No

This solution requires filing with a regulatory body for any extra interruptions. This
seems to be a lot of effort and language for a contingency event that the system is
supposed to be able to handle.

Response: The SDT believes that the stakeholder process is necessary to ensure that Load shed is utilized for single Contingencies
only under limited circumstances. No change made.
Tacoma Power

No

As noted in our response to question 2, regulatory approval is often a slow process
and is not conducive to repeating annually.
Instead of a 25 MW limit, a 300 MW limit that corresponds to the reporting level of
firm demand in EOP-004 is more appropriate.

Response: The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual
assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.

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Question 4 Comment

The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW.
Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75
MW.
Manitoba Hydro

No

The Section III states that regulatory authority approval is required for interruptions
over 25 MW or if voltage level of the contingency is greater than 300 kV. However, a
regulatory authority cannot approve interruption of Firm Demand unless it already
has such jurisdiction that is conferred upon them by legislation. A reliability standard
cannot confer that jurisdiction. Further, the regulator is already part of the proposed
stakeholder group and will have input into the proposal.
The Section III requires the Regional Entity to review the proposed use of Firm
Demand interruption under footnote ‘b’. What impact does it have on the Regional
Entity to necessitate a review, if the stakeholders have already agreed to a process,
TPL Reliability Standards performance requirements have been verified as in Section
II.6, and potential overlapping uses have been assessed with adjacent planners as in
Section II.8. What criteria will the Regional Entity use to make their assessment of
Adverse Reliability Impacts and potential cumulative effects given the above TPL
performance must be met? This requirement can lead to inconsistent decisions
between regions.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

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Independent Electricity
System Operator

Yes or No

Question 4 Comment

No

We generally agree with the instances for which approvals or interruptions are
required. Approval is to be granted by the Reliability Coordinator or applicable
reliability authority. (1) In general, when the footnote is proposed to be utilized as an
interim measure until transmission facilities can be added or reinforced, regulatory
approval must be sought in advance. Having this requirement in a reliability standard
not only is unnecessary, but also introduces regulatory requirements (which provides
no reliability benefit or basis) in a reliability standard. NERC reliability standards
should focus only on BES reliability, not any regulatory requirements. Section III
should therefore stipulate a high-level requirement for the proposing entity to submit
the proposal to the Reliability Coordinator for review and concurrence. The
conditions (1) and (2) for seeking explicit regulatory approval can be retained, but
now become the criteria for seeking review and concurrence by the applicable
reliability authority.
(2) We suggest deleting Item 1 in the first paragraph (with its a and b bullets) and
just indicating that planned Firm Demand interruption requires approval if it is
greater than 25 MW (or other threshold). Requirements for approval of the use of
Firm Demand interruption should be independent of the voltage level of the
contingency.
(3) We propose deleting the sentence in the second paragraph “In no case can the
planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW”. A fixed limit
on the allowable size of Firm Demand interruption can not be technically justified for
the whole continent and each case should be assessed to determine if its impact on
reliability of the bulk transmission system is acceptable or not. The impact of each
case on the affected customers (economic, welfare, etc.) will also be reviewed and
approved by the regulatory authority or governmental body of each jurisdiction and a
“reliability” standard must not impose limits and restrictions pertaining to these
aspects.
(4) The third paragraph proposes that the Regional Entity should review each case of
Firm Demand interruption and verify that there are no Adverse Reliability Impacts.

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Question 4 Comment
We propose instead that the transmission planner or planning coordinator study the
BES performance requirements and the reliability impacts of Firm Demand
interruption, including its correct operation, miss-operation, and the failure to
operate. The transmission planner should then submit a report of this assessment to
the Reliability Coordinator for review and approval.

Response: (1) Regulatory review is not always sought in advance. The SDT believes this review is necessary when the planned Load
shed exceeds either of the thresholds in Section III. No change made.
2) The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the Contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers, and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load shed, it should
require approval even if it is only 1 MW. No change made.
(3) The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also
pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
(4) The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Ameren

No

We do not believe that section III is needed, and particularly if an approval is included
as part of the section I process.
We do not subscribe to dropping Firm Demand (non-consequential load) for single
contingency events, and do not see a need to include a voltage threshold as part of
the contingency requirements. All single contingencies in Category B should be

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Question 4 Comment
applicable.

Response: Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are
included to further define and “put a box” around the situations where first Contingency Load shedding could be employed. Having
the ERO review the application of footnote 12 will provide needed continent-wide consistency.
The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for load dropping, it should
require approval even if it is only 1 MW. No change made.
ReliabilityFirst

No

ReliabilityFirst has a major issue/concern with Attachment 1, Section 3 (specifically
the last paragraph regarding approval). This section requires the Regional Entity to
review each proposed use of Firm Demand interruption under footnote 12 in order to
verify that there are no Adverse Reliability Impacts. The paragraph goes on to
require the Regional Entity to make its determinations and evaluation of Adverse
Reliability Impacts using a published methodology approved by the ERO. First, since
the Regional Entity is not a user, owner or operator of the BES, ReliabilityFirst
believes the Regional Entity should not have requirements placed upon them.
Furthermore there is no guidance on what is required to be placed within the
published methodology. ReliabilityFirst believes this verification is outside the
Regional Entity scope as delegated by the ERO. ReliabilityFirst believes that if such
verification by the Regional Entity is required, it should be specifically laid out in the
NERC Rules of Procedure and not an attachment within a standard.

American Electric Power

No

AEP is concerned that not all Regional Entities are the same in regards to their
engineering and planning staff, and is not confident that they would all have the
resources necessary to perform the required analysis. AEP is concerned by any
attempt to require that a Regional Enity adhere to processes and prodecures that
have not yet been established. FERC has made comments in the past regarding
requirements places upon regional entities (RRO), and while this standard does not

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yet apply, is does indirectly obligate them to rules and procedures not yet
established.

Response: The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order,
is now placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Salt River Project

No

Additional comment from SRP for Q #5.

Response: Please see response to Q5.
City of Austin dba Austin
Energy

No

The 25 MW threshold for Approval of Interruptions of Firm Demand under Footnote
‘b’ is too low. It should be increased to 50 MW because there is an elaborate
Stakeholder process to work through the reliability concerns.

Response: The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the
process threshold at 25 MW. No change made.
Lincoln Electric System

No

For item 1(b) in Section III, LES requests that the drafting team clarify why approval
by the regulatory authority for a generator contingency is based on the high-side
voltage of the GSU rather than the generator capacity. LES believes the generator
capacity, rather than the high-side voltage of the GSU, provides a more consistent
basis for determining necessity for approval from the applicable regulatory authority
or governing body.
Additionally, LES asks for further clarification as to whether the steps referenced for

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Year One of the Planning Assessment extend to Year Two and beyond.

Response: The SDT disagrees that generator capacity is a better basis for determining the necessity for review. The requirements
within the TPL standards have different performance levels based on a 300 kV voltage threshold for the Contingency. This
distinguishes Facilities generally constructed to transmit power from Facilities used to distribute power to Load centers. The SDT
believes this to be a better basis for determining what is important enough to require review from regulatory authorities. No change
made.
The text regarding Year One of the Planning Assessment just means that review from the appropriate regulatory bodies is needed at
least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be determined in the
study of a future year or that review cannot be sought sooner.
LCRA Transmission Services
Corporation

No

See previous comments about use of the term “Firm Demand”.

Response: Please see previous response.
Tri-State Generation &
Transmission Association, Inc.

No

We disagree with the instances for which Approval of Interruptions is required as
proposed by Section III of Attachment I. TPs will develop plans to mitigate BES
performance violations, but those plans may not be able to be constructed in time.
The reason being that the time required to construct a project to mitigate the issues
can take several years. This is due to the need for public input, permitting,
acquisition, and construction. Attachment I does not allow planners to design
temporary mitigation to accommodate real world construction issues, which are
often complex in nature due to competing interests. Attachment I also states that
“Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an
element of a Corrective Action Plan in Year One of the Planning Assessment...” The
need for approval seems burdensome such that it does not allow for temporary
mitigation to meet BES performance criterion while other avenues are explored and
vetted.
The intent of Section III is genuine, but we feel that it is over-reaching for a NERC

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Question 4 Comment
Standard to require action from the applicable regulatory authority or governing
body responsible for retail electric service issues to approval of the use of Firm
Demand interruption under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.

Response: The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate
some of the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will
be completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
Section III is not requiring action from the regulatory authority. It requires action from the Transmission Planner or Planning
Coordinator.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.
Duke Energy

No

Section III is confusing. Are the last two paragraphs of Attachment 1 supposed to be
part of Section III? These paragraphs, when read in combination with the first
paragraph of Attachment 1, seem to say that any time a Firm Demand interruption
using footnote ‘b’ or footnote 12 shows up in the Near-Term Transmission Planning
Horizon, the Stakeholder Process must be invoked. It would seem more reasonable
to invoke the Stakeholder Process only when such interruption occurs in Year One of

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Question 4 Comment
the Planning Assessment.

Response: The last two paragraphs are intended to be included in Section III.
The SDT believes it is more appropriate to require the stakeholder process whenever load interruption is planned in the Near-Term
Transmission Planning Horizon. That allows more time for all interested parties to be informed.
Hydro-Quebec TransEnergie

No

For example, in 1a., it is not clear what is meant by "the stated performance criteria
regarding allowances...". Why is it necessary to give this kind of explanation?
In 1b., the use of the term "non-generator step up transformer" is unusual. Suggest
rewording 1b to read:For a generator or generator step up transformer outage
Contingency, the extra high voltage (EHV) limit applies to the BES connected voltage
(high-side of the Generator Step Up transformer). For any other transformer outage
Contingency, the EHV limit applies to the low-side winding (excluding tertiary
windings).

Response: In the context of the complete sentence, the SDT believes that the comment is clear. No change made.
The terminology is consistent with the Board of Trustees approved TPL-001-2. No change made.
NorthWestern Energy
(NWMT)

No

Comments: A NERC Standard should not require action from a regulatory authority to
approve the use of Firm Demand interruption. There is too much diversity in
regulatory authorities over the industry-wide area. This would increase the work load
of the Regional Entities without improving reliability. We suggest removing Section III
of Attachment 1.

Response: The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help
alleviate some of the concerns..
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under

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footnote ‘b’ if either:
Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are included to
further define and “put a box” around the situations where first Contingency Load shedding could be employed. The SDT believes
that an evaluation by the ERO of the potential for adverse system impacts is needed to provide continent-wide consistency.
Therefore, Section III is needed. No change made.
Georgia Transmission
Corporation

No

GTC would appreciate if the SDT could please clarify if the approval of a regulatory
authority or governing body is referring to the Regional Entity.The first sentence in
Section III:”Approval of the use of Firm Demand interruption under footnote 12 by
the applicable regulatory authority or governing body responsible for retail electric
service issues is required if either:...”

Response: No, that sentence refers to regulatory authorities such as a state public service commission.
ISO New England Inc.

No

Section III describes the instances where Approval of Interruptions of Firm Demand
are required under footnote 12. It is not clear whether under Paragraph III.1.a and
Paragraph III.1.b the Transmission Planner is to base the determination on either
contingency or both contingencies i.e. is “and” logic to be applied or is “or” logic
used? Paragraph III.2 requires such approval for interruption equal to or greater than
25 MW, this is a very small amount of load to be required to bring to a stakeholder
approval process for second contingency events. This amount should be increased to
at least 100 MW.
Additionally in Section III, it is not clear who the “regulatory authority or governing
body responsible for retail electric service issues” is. Having this requirement in a
reliability standard not only is unnecessary, but also introduces regulatory
requirements in a reliability standard. NERC reliability standards should focus only on
BES reliability, not any regulatory requirements. The Attachment goes on to state
“The Regional Entity determinations of Adverse Reliability Impacts are to be
evaluated by the Regional Entity through a published methodology approved by the
ERO”. This is essentially a “fill in the blank” requirement and makes it necessary to

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Question 4 Comment
comment and approve the footnote attachment without the benefit of reviewing a
proposed methodology.

Response: Section 3 clarifies the criteria for the application of footnote 12. Items 1 and 2 are included to further define and “put a
box” around the situations where first Contingency Load shedding could be employed; as such, they are an “or” requirement and the
‘or’ has been added to the Attachment.
The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
The regulatory or governing body should be known by the entity who plans to use footnote 12.
South Carolina Electric and
Gas

No

See response to question #1

Response: Please see response to Q1.
Electric Reliability Council of
Texas, Inc.

No

If non-consequential load shedding is allowed for single contingency conditions, as
discussed above, it should be based on objective critieria. As such, there is no need
for the proposed stakeholder process, including the Section III instances requiring
regulatory approval. As with the other stakeholder process sections, that section
should be eliminated.

Response: Industry and the NERC BOT have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The SDT is now attempting to address FERC’s concern expressed in their Remand
Order 762 that NERC’s proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for
planned Load shed in a single Contingency provided that the plan is documented and alternatives are considered in an open and
transparent process, is vague, unenforceable, and not responsive to the previous Commission directives on this matter. The draft
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posted for comment adds detail and specificity to the already-approved approach. The SDT does not believe it appropriate to move
away from the industry and BOT approved Stakeholder Process approach. No change made.
Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are included to
further define and “put a box” around the situations where first Contingency Load shedding could be employed. The SDT believes
that an evaluation by the ERO of the potential for adverse system impacts is needed to provide continent-wide consistency.
Therefore, Section III is needed. No change made.
San Diego Gas & Electric

No

Public Utility District No. 1 of
Snohomish County

No

Response: Without specific comments, the SDT is unable to respond.
Orlando Utilities Commission

Yes

Comment #1: The maximum threshold should be in the Footnote, not in the
Attachment.
Comment #2: I think the role identified for the Regional Entity is appropriate.
Comment #3: I like the concept that regulatory approval is not required until year
one. However I think either the ordering of language or the formatting needs to be
changed to make it clear that the year one applies to only those that need regulatory
approval. Maybe change the section to read... "Section IIIFirm Demand
Interruptions under footnote 'b' that meet either or both of the criteria below are
required to have approval by the applicable regulatory authority or governing body
responsible for retail electric service issues. The regulatory approval is required prior
to the use of that remedy in Year One of a Corrective Plan in the Planning
Assessment. (Existing 1 & 2)(Existing RE Review)

Response: The maximum threshold is the last sentence of the footnote, and is also cited in Section III of the Attachment. No change
made.

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Question 4 Comment

The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some of
the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will be
completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
LCEC (Lee County Electric
Cooperative

No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

CPS Energy

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

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5.

If you have any other comments on this Standard that you haven’t already mentioned above, please provide them here.

Summary Consideration: Many commenters proposed changes to the applicable planning events for which footnote 12 applies in
the new proposed TPL-001-2a standard. The SDT clarifies that the planning events for which footnote 12 are applicable were
already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011) in its consideration of TPL-001-2. The proposed
changes are outside the scope of this project, which aims to clarify the stakeholder approval process.
Some commenters indicated confusion surrounding changes made to footnote 12 and Attachment 1 in the proposed TPL-001-2a
standard in regard to the use of the term Firm Demand interruption. The SDT acknowledges that the references to Firm Demand
Interruption should reference Non-Consequential Load Loss in footnote 12. The SDT has made revisions to the TPL-001-2a Footnote
12 and Attachment I to show these changes.
Some commenters continue to weigh-in on FERC’s jurisdiction in regard to continuity of service to Load. FERC Order 762, beginning
at Paragraph 23, discusses FERC’s position on jurisdictional issues. This topic was well-vetted in the development of TPL-001-2, and
FERC’s subsequent NOPR and is beyond the scope/authority of this drafting team.
The following change was made due to industry comments:
Effective date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first calendar quarter, 60
months after approval by applicable regulatory authorities. In those jurisdictions where regulatory approval is not required, the
effective date will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other requirements remain in effect per previous
approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.
Attachment 1 – Section I, last paragraph: An entity does not have to repeat the stakeholder process for a specific application of
footnote ‘b’ utilization with respect to subsequent Planning Assessments unless conditions spelled out in Section II below have
materially changed for that specific application.
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing
body responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.

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NorthWestern Energy
(NWMT)

Question 5 Comment
Comments: Footnote 12 should be added to Category P2 Single Contingency Event
2, Bus Section Fault, and to Category P2 Single Continency Event 3, Internal Breaker
Fault , for EHV in the Non-Consequential Load Loss column.

Response: The planning events for which footnote 12 are applicable within the proposed TPL-001-2 standard were already vetted by
industry and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
ACES Power Member
Standards Collaborators

(1) The standard needs to allow more flexibility regarding the use of planned load
shed to address transmission performance issues in the planning horizon. It needs to
recognize that these planned load shedding events may only be preliminary decisions
for addressing problems that are several years away. If there is little chance that the
planned shed load will ever be relied upon in the operating time horizon, there
should be much less stringent requirements. For instance, if a PC or TP relies on
planned load shed for year five of the planning horizion but year one does not utilize
the planned load shed, they have four years to develop another solution. Why
should great effort and resources be expended in year five when another solution will
likely be developed?
(2) This standard does not consider if the local regulatory body will act in time to
approve the use of planned Firm Demand interruption. We believe the standard
needs to consider that the Planning Coordinator and Transmission Planner may not
be able to control the timelines of local regulatory agencies. As long as the PC and TP
have done their part by submitting the data, they should be able to rely on the
planned Firm Demand interruption until the local regulatory body acts. If the
planned Firm Demand interruption is not approved, then the TP and PC should be
given more time to address the transmission performance deficiency.
(3) Several terms are used for the use of planned load shed. Non-consequential load
loss and Firm Demand interruption are two examples. We suggest using one term
consistently throughout the standard.

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Question 5 Comment

Response:
(1) For reasons similar to those raised by the commenter, the SDT limited Attachment 1 as being applicable only to planned use of
Firm Demand interruption in the Near-term Planning Horizon (Years 1-5), recognizing that plans may change. The SDT believes it
is appropriate to require the stakeholder approval process in the Near-term Planning Horizon. The Near-term Planning Horizon
plans should become more stable over those identified on the Long-term Planning Horizon. No changes made.
(2) The SDT has clarified the language concerning regulatory approval to show that review is what is actually required. Review by the
regulatory authority or governing body responsible for retail electric service issues is only required in certain instance of planned
Firm Demand interruption and if planned for use in Year One of the Near-Term Transmission Planning Horizon. When required,
the indicated review must be obtained before it can be part of a Corrective Action Plan. Until such review, the planner would
need to consider and list alternate Corrective Action Plans within its assessment. The SDT has also clarified that such reviews
need only be done once, unless material changes have taken place. The SDT believes that these changes should alleviate the
majority of lead-time concerns, although an entity should always build sufficient time for the process to play out into its planning
cycle.
(3) An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
(4) Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
(5) The terms used are appropriate since the existing FERC-approved TPL standards and the proposed TPL-001-2 (NERC Board of
Trustees approved 8/4/2011) use differing terminology for the common topic (planned load shed) of both footnote ‘b’ (Firm
Demand Interruption) and footnote 12 (Non-Consequential Load Loss). The SDT acknowledges that the reference to Firm
Demand Interruption should reference Non-Consequential Load Loss. The SDT has made appropriate revisions to proposed TPL001-2a, Attachment I.
Independent Electricity
System Operator

(1) We’d like to reiterate our support for allowing load interruption for a single
contingency with sufficient review/oversight and under acceptable conditions,

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment
including no adverse impact on the reliability of the bulk electric system. The
reliability aspects (BES performance requirements) should be reviewed/approved by
the Reliability Coordinator. However, issues pertaining to economics or externalities
which may not be directly reliability-related are always available for review and
debate by the stakeholders via the regulatory processes and subject to approval by
the regulatory authority of each jurisdiction (particularly those in Canada and
Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2 approved
by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow
the same load interruption that is allowed for the related P1 contingency. Table 1
currently does not allow any load to be interrupted for an EHV single contingency if
the primary circuit breakers fail to clear the fault (Category P4, “Fault plus stuck
breaker”). But if load X is allowed to be interrupted for a single EHV transmission line
contingency (Category P1), it should be allowed to interrupt the same load X if the
primary breaker fails and the fault is cleared by other breakers. Similarly, if the same
breaker has an internal fault or there is a fault on the same bus section (Category P2)
or there is a failure of a relay (Category P5), which results in the loss of the same EHV
transmission line, it should be allowed to interrupt the same load X.
(3) We suggest that NERC Standards and their requirements should focus on what is
the anticipated outcome rather than how to achieve them. Accordingly, we believe
that the focus of the foot note ‘b’ should be that interruption of load must not
adversely impact the reliability of the interconnected BES because reliability of supply
to load and/or supply continuity is mandated by the jurisdictional authority.
(4) We submit that the scope of NERC’s mandatory standards does not extend to
assessing or setting requirements for non-jurisdictional entities, unless such facilities
are necessary for the operation of the interconnected BES or have an adverse impact
on its reliability. For Canadian entities there are regulatory requirements and
processes under the purview of the relevant regulatory authorities that we believe
are adequate. Accordingly, customer interests are protected and are not subject to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment
unilateral decisions of the transmission planner. In all cases, steps are taken at the
planning, design, and operations stages of system development such that nonconsequential Firm Demand interruption would not adversely impact the BES and the
affected customer has been given the opportunity to avail themselves of other
options under the transmission development rules in the relevant jurisdictions.
(5) The requirements of the footnote (including attachment) will amount to a
mandate to construct additional transmission which is inconsistent with Section 215
(i) (2) of the US Federal Power Act which specifically does not authorize the ERO “to
order the construction of additional generation or transmission capacity or to set and
enforce compliance with standards for adequacy or safety of electric facilities or
services.
(6) We suggest that NERC should not include and/or address load reliability or load
supply continuity requirements within the BES Reliability Standards. In Canada, these
requirements and approvals are with relevant reliability or regulatory authority. If
NERC feels obligated to include such requirements for load reliability issues in US,
then we propose that non-jurisdictional entities must be exempted from these
requirements similar to the provisions in NUC 001.
(7) The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after each “applicable
regulatory approval” in the Effective Dates Section A5 of both draft standards, to the
following effect: “, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.”

Response:
(1) The SDT thanks you for your general support of the proposed stakeholder process. It’s anticipated that the Reliability
Coordinator will be a stakeholder participant and could raise any concerns they believe are warranted. The SDT appropriately
set the BES reliability approval to the Regional Entity with ERO backstop authority per FERC Order 762, Par. 55. Paragraph 55
states in part: “NERC and the Regional Entities provide both objectivity in the decision-making process as well as the necessary
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment

reliability-focused expertise.” No change made.
(2) The planning events for which footnote 12 is applicable within the proposed TPL-001-2 standard were already vetted by industry
and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project which
aims to clarify the stakeholder approval process. No change made.
(3) The proposed Attachment 1 achieves the view stated by the commenter. BES Reliability is assured by the Regional Entity and
ERO where warranted. The approval by the regulatory authority or governing body responsible for retail electric service issues
addresses continuity of service to end-use Load. No change made.
(4) The proposed Attachment 1 process appropriately sets governance for both the ERO and Regional Entities to ensure no Adverse
Reliability Impact of the BES. If existing processes are already in place to ensure end-use Loads are appropriately protected,
those processes may be utilized to fulfill the Attachment I obligations. No changes made.
(5) FERC Order 762, beginning at Paragraph 23 discusses the FERC’s position on jurisdictional issues that are raised by the
commenter. This topic was well-vetted in the development of TPL-001-2 and FERC’s subsequent NOPR and is beyond the
scope/authority of this drafting team. No changes made.
(6) There are no current exemptions in the TPL standards, and it is not within the scope of the SDT to introduce any at this time. No
change made.
(7) The SDT has revised the effective date language to reflect the latest guidance received from the Standards Committee.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first calendar quarter, 60 months
after approval by applicable regulatory authorities. In those jurisdictions where regulatory approval is not required, the
effective date will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.
MISO

(1) The process described in Attachment 1 may be more suited for inclusion in the
Rules of Procedure, similar to the process required for seeking BES facility exceptions.
We urge the SDT to consider moving Attachment 1 into a proposed RoP instead of

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment
stipulating it in the standard.
(2) It may be more appropriate to develop a Standards process that covers the
technical aspects of using a footnote 12 and leave regulatory review and approval to
FERC and State agencies.

Response:
(1) The SDT respectfully disagrees with the commenter. Inclusion of the Attachment 1 text within the Rules of Procedure might be
appropriate for consideration if the process had wide impact on multiple NERC reliability standards. As such, since limited to use
within the TPL standards, its inclusion directly within the TPL standard(s) is applicable. No changes made.
(2) The SDT believes the Attachment 1 process strikes the appropriate balance of regulatory oversight. BES Reliability is assured by
the Regional Entity and ERO where warranted by assessing any Adverse Reliability Impact. The regulatory authority or governing
body responsible for retail electric service issues addresses continuity of service to end-use Load. No change made.
Deseret Generation &
Transmission Cooperative
Salt River Project
Los Angrles Department of
Water and Power
Tri-State Generation &
Transmission Association, Inc.
nevada power company dba
nvenergy
PG&E Company

: The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it
is applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV in P1 is of no value.
The footnote 12 should be added to Category P2 Single Contingency Event 3 Internal
Breaker Fault for EHV in the Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a

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bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore
the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 3The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.

Hydro-Quebec TransEnergie

Footnote 12 is not applied to Categories P4 and P5, which would include a EHV stuck
breaker or failure of a non-redundant relay for a Multiple Contingency. The Load loss
restriction for the contingencies listed in P4 and P5 is more restrictive than for the
loss of a EHV double circuit line. Statistics indicate that the contingencies presented
in P4 and P5 are less frequent. HQT requests that Footnote 12 should also be used for
P4 and P5 contingencies for EHV. Even though considering Firm Demand
interruption in planning might not be common practice, HQT agrees that the
proposed Footnote 12 should maintain such a possibility.

Response: The planning events for which footnote 12 are applicable within the proposed TPL-001-2 standard were already vetted by
industry and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
Essential Power, LLC

As written, this change is complex and will be difficult to execute without additional
turmoil on the planning end and offers limited clarification. Some additional issues to
consider;1. Should this level of contingency allow isolation/removal of load or
generation if not part of the outage?
2. Should additional generation be allowed to be removed, again considering the
contingency level?

Response: 1. The binary question of applicable use was well vetted during the development of both the revised footnote ‘b’ and
footnote 12. It is clear that some use, appropriately bounded, is the desire of industry and FERC. The SDT believes the proposed
Attachment 1 provides the clarity sought by FERC in its remand of footnote ‘b’ and that the process is reasonable in its approach. No

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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changes made.
2. Generation is not addressed in footnote ‘b’. No change made.
Public Utility District No. 1 of
Snohomish County

Comments: SNPD generally disagrees with the draft process that has been
developed, and notes that infrequent interruption of small amounts of nonconsequential load under limited conditions that does not negatively impact a
neighboring TOP is not a reliability issue. Instead it is a cost of service and customer
service matter best left to the local and state regulatory bodies. The time and
resources spent on this issue at the national level diverts scarse resources and
attention from more important efforts that might actually benefit the reliability of
the BES.
SNPD supports the Pacificorp Revision of TPL-002 footnote ‘b’ and TPL-001 footnote 1
Comments- The proposed revisions will require regulatory approval for interruptions
of firm demand under TPL-002 footnote b or TPL-001 footnote 12 if the voltage level
of the contingency is greater than 300 kV with certain sub-conditions or if the
planned interruption of firm demand under these footnotes is greater than or equal
to 25 MW. The 2011 peak winter and summer loads in the Western Electricity
Coordinating Council (WECC) region were 131,471 and 152,211 MW respectively.
Total installed generation is 229,189 MW. There are 120,385 miles of AC
transmission lines 100 kV and above, and of that total, 31,138 miles of AC
transmission lines are operated at voltages above 300 kV. There are 1,744 miles of
DC transmission lines.The proposed revisions would add considerable process and
documentation for any interruptions, and will require regulatory approval if the
interruption is greater than 25 MW. This is 0.016 percent of the WECC peak load.
The planning standards already require Category B1 contingencies to be considered
which result in the loss of a single generator since individual generator units range in
size up to more than 1000 MW. Since these contingencies are routinely studied, it is
very, very difficult to imagine that the loss of 25 MW or more of firm demand under
TPL-002 footnote b or TPL-001 footnote 12 is so critical to the reliability of the BES
that it deserves not only a lengthy footnote, but a two page attachment detailing a

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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complex and lengthy process detailing requirements public meetings, procedures for
questions, specifications for documentation, and even a dispute resolution process.
As this is not a BES reliability issue, any action regarding potential curtailments of
local loads should occur at the local level where the cost and benefit of
improvements can be properly assessed.
The recent blackout that left 2.7 million
customers in Southern California, Arizona and Baja California without power was not
due to planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system. SNPD is not aware of any regional
disturbances or cascading events that were due to planned or controlled
interruptions of electric supply where a single contingency occurred on a
transmission system. As these proposed requirements could be removed from the
Reliability Standards with little or no effect on reliability and would, if anything,
increase the efficiency of the ERO compliance program, the proposed limitations on
curtailment of firm demand under TPL-002 footnote b or TPL-001 footnote 12 should
be removed.

Response: The feedback offered is largely aimed at FERC’s jurisdictional issues in regard to continuity of service of end-use Load.
FERC Order 762, beginning at Paragraph 23, discusses the FERC’s position on jurisdictional issues that are raised by the commenter.
This topic was well-vetted in the development of TPL-001-2 and FERC’s subsequent NOPR and is beyond the scope/authority of this
drafting team. No changes made.
In regard to support offered for the Pacificorp proposal, we direct the commenter to view the SDT response to Pacificorp comments.
Tacoma Power

FERC order 762 states that "to plan for the loss of firm service at the fringes of
various systems would be an acceptable approach.” The newly defined contingency
P2.1 requiring analysis of open ended line sections should allow load shedding of the
load on the line section as suggested in the FERC order.

Response: As P2.1 already includes footnote 12, the SDT is assuming that you are supporting the SDT position and thanks you for
your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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San Diego Gas & Electric

Question 5 Comment
In FERC Order 762, FERC rejected NERC’s footnote (b) and urged “...NERC to develop
modifications responsive to the Commission’s directives in Order No. 693 and our
concerns set forth in this final rule.” The NERC SDT has done little to address FERC’s
concerns and instead has resubmitted the same document with additional language.
Order 693 directed NERC to develop modifications to TPL-002-0, which clarify
footnote (b). As redrafted, footnote (b) does not address FERC’s concerns. For
example, footnote (b) continues to use the term “Firm Demand,” which describes all
forms of demand whether served by the faulted element or not. On the contrary,
“consequential load loss” is load, which is removed as a result of a fault. Clearly,
these are different concepts and the new language does not comply with FERC’s
directive. FERC’s position has been that non-consequential load loss through load
shedding shall not be allowed as an exception to TPL-002-0. Also, FERC has stated
that the interruption of Firm Transmission not be allowed as an exception. But,
Footnote (b) continues to say, “Curtailment of firm transfers is allowed ...”. Another
inconsistency. Beyond the differences between what FERC directed NERC to do and
what NERC did, as written, footnote (b) would introduce “stakeholder interests” into
tranmission reliability even if those interests do not promote reliability. The TPL
standards identify the Planning Authority and Transmission Planner as the entities
responsible for meeting the standards and makes no mention stakeholders. To meet
the reliability objectives of the standard, the Planning Authority and Transmission
Planner are subject to Measures and the Compliance Monitoring Process. In FERC
Order 762, FERC determined “...that openness and transparency do not alone ensure
bulk electric system performance criteria will be met...” and was “...not persuaded
that developing technical criteria is unachievable.” Although FERC does not disagree
with adding a stakeholder process, clearly, they do not endorse one and prefer a
technical approach to creating the exception under footnote “b”.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Consolidate Edison Co. of NY,
Inc.

Planned interruptions of Firm Demand in response to a Single Contingency (as
directed in Footnote b of TPL-002 Table 1, is not an acceptable corrective action to
mitigate reliability issues on the BES system. The Interconnected System should be
designed and operated with enough transfer capacity to be able to withstand, at a
minimum, a single contingency event without service interruptions to customer load.
Systems must be designed and operated so that the impact of any single contingency
can be mitigated by re-dispatching available system resources without the need to
implement load shedding.

Response: The binary question of applicable use was well-vetted during the development of both the revised footnote ‘b’ and
footnote 12. It is clear that some use, appropriately bounded, is the desire of industry and FERC. The SDT believes the proposed
Attachment 1 provide the clarity sought by FERC in its remand of footnote ‘b’ and that the process is reasonable in its approach. No
changes made.
Manitoba Hydro

Please clarify if an entity must set up a stakeholder process if Firm demand
interruption is not used as an element of the Corrective Action Plan. As I understand
it, the footnote b in TPL 002 will be replicated in the other relevant TPL standards
once it is approved. When it is included in the other TPL standards, will it be
customized to each standard, or will it appear exactly the same in each standard?
Footnote 12 of TPL-001 as currently drafted seems a bit disjointed or incomplete - i.e.
its referring to Non Consequential Load Loss and then it refers you to an Attachment
for the calculation of Firm Demand interruption without providing a connection

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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between the two concepts .

Response: A process would only be required if an entity allows or intends to utilize planned Load shed to meet the performance
requirements for single Contingency (N-1) events. The commenter is correct that the final footnote ‘b’ and Attachment 1 will be
replicated in the other currently-enforceable TPL standards – TPL-001, TPL-002, TPL-003 and TPL-004. The SDT acknowledges that
the references to Firm Demand Interruption should reference Non-Consequential Load Loss. The SDT has made revisions to the TPL001-2a Footnote 12 and Attachment I to show these changes.
TVA Transmission Reliability
Engineering & Controls

Please see answer to question #1. TVA beleives that only load drops of higher
magnitudes go thru the Stakeholder and regulatory review.

Response: Please see response to Q1.
BrightSource Energy, Inc.
Utility System Efficiencies, Inc.

The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is
applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV inconsistent with P1.The footnote 12 should
be added to Category P2 Single Contingency Event 3 Internal Breaker Fault for EHV in
the Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a
bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 2The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.
The new definition of Non-consequential Load Loss compared to the last version
seems to have deleted the reference to Loads that may be lost during transient
conditions due to under-frequency load shedding (UFLS), while the reference to Load
Loss due to under-voltage load shedding (UVLS) is retained. As a result Load Loss due
to UFLS would be part of Non-consequential Load Loss, and will not be allowed under
single contingency. Because UFLS may also be triggered during transient simulations,
please change the definition for Non-consequential Load Loss to read:”NonConsequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load or frequency
sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.”It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting
steady state reliability requirements. Therefore, in Table 1, please change headernote “i” to read:”The response of voltage sensitive Load and Frequency 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.”

Response: 1 & 2. The SDT disagrees that the use of Footnote ‘b’ between P1 and P2 for EHV is inconsistent. The SDT believes that
the system should be planned so that a fault on an EHV bus section or an internal fault on a non-bus-tie EHV breaker should not
require planned Load loss to resolve system performance issues. The planning events for which footnote 12 is applicable within the
proposed TPL-001-2 standard were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011). The
proposed changes are outside of the scope of this project, which aims to clarify the stakeholder approval process. No change made.
3. The definitions have not been revised, since the standard was approved by the NERC Board of Trustees and changes to those
definitions are not in the scope of this project. No change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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California Independent
System Operator

Question 5 Comment
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is
applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV in P1 is of no value.The footnote 12 should be
added to Category P2 Single Contingency Event 3 Internal Breaker Fault for EHV in the
Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a
bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore
the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 3The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.
The process described in Attachment 1 may be more suited for inclusion in the Rules
of Procedure, similar to the process required for seeking BES facility exceptions. We
urge the SDT to consider moving Attachment 1 into a proposed RoP instead of
stipulating it in the standard.

Response: 1 & 2. The SDT disagrees that the use of footnote ‘b’ between P1 and P2 for EHV is inconsistent. The SDT believes that the
system should be planned so that a fault on an EHV bus section or an internal fault on a non-bus-tie EHV breaker should not require

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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planned Load loss to resolve system performance issues. The planning events for which footnote 12 is applicable within the
proposed TPL-001-2 standard were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011). The
proposed changes are outside of the scope of this project, which aims to clarify the stakeholder approval process. No change made.
3. The SDT disagrees that the attachment should be moved to the NERC Rules of Procedures. Inclusion of the Attachment 1 text
within the Rules of Procedure might be appropriate for consideration if the process had wide impact on multiple NERC reliability
standards. As such, since limited to use within the TPL standards, its inclusion directly within the TPL standard(s) is applicable. No
changes made.
Georgia Transmission
Corporation

The current draft for Requirement 5 (R5) of the NERC Standard TPL-001-3 Draft 1
reads as follows:”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.”GTC has the
following comments regarding TPL-001-3, R5:If the responsible entity has criteria for
transient voltage response, along with criteria for acceptable system steady state
voltage (including a pre-contingency high and low voltage limit, and a postcontingency high and low voltage limit), then having a steady state post-contingency
voltage deviation criteria does not affect the reliability of the bulk electric system
(BES). If the system response to a disturbance were to violate either the transient
response criteria, or the steady state maximum/minimum voltage criteria, there is
potential for loss of integrity of the BES. There is little to no potential for a loss of
system integrity due soley to a violation of the steady state voltage deviation criteria.
Therefore, Georgia Transmission Corporation requests that R5 not include a
requirement to have criteria for post-Contingency voltage deviations.

Response: Requirement R5 requires the Transmission Planner and the Planning Coordinator to have established voltage criteria for
their system. This set of criteria is necessary to ensure that the planners are evaluating the voltage excursions (transient and steady
state) against their performance criteria. The standard requirements have not been revised since the standard was approved by the
NERC Board of Trustees, and changes to those requirements are not in the scope of this project. No change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Salt River Project

Question 5 Comment
The new definition of Non-consequential Load Loss compared to the last version
seems to have deleted the reference to Loads that may be lost during transient
conditions due to under-frequency load shedding (UFLS), while the reference to Load
Loss due to under-voltage load shedding (UVLS) is retained. As a result Load Loss due
to UFLS would be part of Non-consequential Load Loss, and will not be allowed under
single contingency. Because UFLS may also be triggered during transient simulations,
please change the definition for Non-consequential Load Loss to read:”NonConsequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load or frequency
sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.”It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting
steady state reliability requirements. Therefore, in Table 1, please change headernote “i” to read:”The response of voltage sensitive Load and Frequency 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.”

Response: The definitions have not been revised since the standard was approved by the NERC Board of Trustees, and changes to
those definitions are not in the scope of this project. No change made.
MRO NSRF

The NSRF has concerns that over regulation of footnote “b” or “12” could cause lost
opportunities for legitimate growth. An example condition would be the
development of a large load in a relatively weak transmission area. Many times new
large loads need open undeveloped areas to locate. Without the footnote “b” or
“12” option, could an entity be forced to turn away legitimate load growth? The key
being that an entity could serve the new large load under normal conditions with
easy quick upgrades, but would need 5 - 7 years to construct additional transmission
to meet N-1 conditions? Therefore the entity would need to turn away new growth
because of over regulation on footnote “b” or “12”.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Response: The SDT does not believe that the proposed revision to footnote ‘b’ (or footnote 12) will restrict an entity’s ability to serve
new Load. The SDT has attempted to find a balance between being overly prescriptive and allowing entities the tools they need for
planning purposes while responding to the remand from FERC. No change made.
LCRA Transmission Services
Corporation

The primary objection to Footnote 12 is twofold:1. Application to the P3 contingency.
This contingency is a Category C contingency under the current NERC TPL-003
standard and allows for load shedding. Thus, the proposed standard revision is a
significant and substantial increase in the reliability standard.
2. Use of the term “Firm Demand” as opposed to “Non-Consequential Load Loss.” The
NERC Glossary defines Firm Demand as “That portion of the Demand that a power
supplier is obligated to provide except when system reliability is threatened or during
emergency conditions” and Demand as “The rate at which electric energy is delivered
to or by a system or part of a system, generally expressed in kilowatts or megawatts,
at a given instant or averaged over any designated interval of time.” Thus
interruption of Firm Demand may not result in Non-Consequential Load Loss. Therm
“Firm Demand” should be replaces with “Non-Consequential Load Loss.”

Response: 1. Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
2. The SDT determined that it was appropriate to maintain the existing headers in the existing TPL standards and begin using “Non-

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Consequential Load Loss” with the new TPL-001-2. No change made.
Electric Reliability Council of
Texas, Inc.

The SDT is not required to utilize the stakeholder approach by Order 762 or any other
relevant FERC orders. FERC merely provided guidance as to how the rejected
proposal could be improved. However, if the SDT elects to pursue an exception
process, such exceptions should be based on objective criteria, and the process
should be external to the NERC Reliability Standards (e.g. in the Rules of Procedure).
In Order 693, FERC directed NERC to clarify footnote (b) to prohibit shedding firm
load except for consequential load loss (Order 693 at PP 1773, 1794 and 1797). In a
related compliance order, FERC reaffirmed its position. (130 FERC ¶ 61,200 (March
18, 2010) at PP 8-10 (Compliance Order)) In a subsequent order, FERC clarified that
its Order 693 directive did not preclude consideration of specific comments related to
planning the system based on load shedding at the “fringes” of a system. (131 FERC
¶ 61,231 (June 11, 2010) at P 21 (Clarification Order)) FERC held that regional
variances for case-specific circumstances or a case-specific exception process to plan
for the loss of firm service “at the fringes of various systems” would be acceptable.
(131 FERC ¶ 61,231 (June 11, 2010) at P 21 (Clarification Order)) However, FERC
also stated that it viewed the basis for such exceptions as economic, not reliability,
with the justification being that it was not economic to invest in the bulk electric
system to serve all non-consequential load customers under some single contingency
conditions. (Order 693 at P 1792) FERC made clear that any such regional differences
or case specific exception processes cannot reflect the lowest common denominator,
and, they must be technically justified, and such justification must be strong.
(Clarification Order at P 21. See also Order 693 at P 1794) This is consistent with
FERC’s position that this is a matter of “fundamental issue of transmission service”.
(Order 693 at P 1793) In recognizing that meeting firm demand under single
contingency conditions is fundamental to transmission service, FERC noted that
NERC’s definition of firm transmission service is the "highest quality (priority) service
offered to customers...that anticipates no planned interruption.” (Order 693 at P
1793)Against this background, NERC filed revisions to footnote b that allowed
transmission plans to shed non-consequential load under single contingency

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, (139 FERC ¶ 61,060 (April 19, 2012))
FERC rejected the approach proposed by NERC and provided guidance on acceptable
approaches to footnote b. However, FERC did not endorse or mandate any particular
approach. Rather, it merely urged “NERC to develop in a timely manner an
appropriate modification that is responsive to the Commission’s directives in Order
No. 693 and our concerns set forth in this Final Rule.” (Order 762 at P21) FERC stated
that in order for any such proposal to have merit, it must be technically justified and
must not reflect the lowest common denominator.As discussed, the proposed
stakeholder approach is not appropriate for NERC Reliability Standards. The SDT
should abandon that approach and consider simple revisions to footnote b that
reference a case by case exception process based on objective criteria that is external
to the NERC Reliability Standards (e.g. Rules of Procedure). Alterantively, it should
develop revisions to the continent-wide standards that clarify that non-consequential
load shedding is not generally permitted for single contingency conditions, but,
consistent with FERC’s orders, exceptions could be established pursuant to regional
rules based on the need/appropriateness in a particular region. Consistent with the
above discussion, if the SDT elects to pursue revisions that accommodate shedding
non-consequential load in transmission planning for single contingency conditions, it
should abandon the stakeholder process approach. The establishment of exceptions
is better suited for regional rules or pursuant to a process outside of the reliability
standards - e.g. via the Rules of Procedure, because such a process is not suited for a
continent-wide reliability standard. Regardless of whether the issue is addressed via
an external process, or left to regional variances, this issue needs to be addressed in a
relatively timely manner because the uncertainty is affecting planning processes.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

11
7

Organization

Yes or No

Question 5 Comment

remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Southern Company

The use of load dropping should be limited to being only an interim solution while a
project is being completed and nothing else can be done.

Response: An entity can choose to restrict the use of footnote ‘b’ to an interim solution but the SDT believes that there are instances
where a long term use (permanent or near-permanent) of footnote ‘b’ may be appropriate. For example, the amount of Load
involved versus the probability of occurrence might dictate that a long term use is in the best overall interests of the customers. No
change made.
Arizona Public Service
Company

This process is too prescriptive and must be simplified.

Response: Without specific comments, the SDT is unable to respond.
Ameren

To clarify, the Stakeholder Process should not be initiated until the amount of Firm
Demand expected to be interrupted by the TP or PC as mitigation reaches a threshold
of 10 MW. However, at that point, the Stakeholder Process should commence, but
not without incorporating the need to obtain approvals from the stakeholders,
regardless of the amount of load to be interrupted beyond the 10 MW threshold
level, and regardless of the voltage level of the transmission elements involved in the
contingency event(s). As drafted, the Stakeholder Process appears to be silent on
receiving approvals to drop load of less than 25 MW. We believe that this is an
invitation to trouble for the industry. For example, if a TP or PC were to have a
contingency for which the mitigation is to interrupt 15 MW of Firm Demand, all the
stakeholders would be called in just to inform them that their load is subject to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

11
8

Organization

Yes or No

Question 5 Comment
interruption, but their displeasure is not relevant, because the 25 MW interruption
level had not been reached, and approval is not required. Thus, we believe that as
drafted Stakeholder Process needs some additional work before we could support it.

Response: The stakeholder process is required anytime that Load is planned to be interrupted pursuant to footnote ‘b’. Approval by
the applicable regulatory authority or governing body responsible for retail electric service issues is required for planned
interruptions greater than 25 MW. The SDT believes that this level is the appropriate balance to protect the interests of the
customers without being unduly burdensome. No change made.
Southwest Power Pool
Reliability Standards
Development Team

We agree the distinction between consequential and non- consequential is
necessary. We don’t agree that you should plan for non-consequential load
loss/shed. You shouldn’t have to interrupt firm service for n-1 contingency.

Response: The SDT believes that there are instances where use of footnote ‘b’ may be appropriate. For example, the amount of
Load involved versus the probability of occurrence might dictate that a use of footnote ‘b’ is in the best overall interests of the
customers. No change made.
Nova Scotia Power

With regard to the application of Footnote 12 in TPL-001-3, the footnote is only
applied to the contingencies in Table 1 involving loss of a Single Line with a 3 phase
fault (P1) or opening of a line without a fault (P2-1). These are higher probability
events relative to other types of contingencies, and Footnote 12 allows for loss of
load for these events, but does not allow for loss of load for lower probability events
that have the same results, such as P2-2 and P2-3. Take for example a single radial
345kV line feeding a small radial portion of the system, with a line end transformer
and breaker between the transformer and the line. Application of Footnote 12 to
only a P1 event (loss of the line on its own, or loss of the transformer on its own) but
loss of the breaker between the line and the transformer would not be allowed, even
though the result would be the same. Without applying footnote 12 to category P2-2
and P2-3 would mean that Footnote 12 is rendered moot (can never be used).
Similarly, Footnote 12 should be applied to P4 and P5, essentially wherever Footnote
9 is applied, otherwise Footnote 12 can never be applied.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

11
9

Organization

Yes or No

Question 5 Comment

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT believes that the system should be planned so that a fault on an EHV bus section (or an internal fault on a non-bus-tie EHV
breaker) should not require planned Load loss to resolve system performance issues. No change made.
Northeast Power Coordinating
Council

NPCC reviewed the posted documents, and has no comments for this posting.

END OF REPORT

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

12
0

Consideration of Comments

Project Revision of TPL-002 footnote ‘b’ and TPL-001 footnote 12
The Project 2010-11 Drafting Team thanks all commenters who submitted comments on the proposed
standards, TPL-002-1c and TPL-001-2a. The standards were posted for a 45-day public comment
period from October 5, 2012 through November 19, 2012 with the initial ballot period from November
9, 2012 to November 19, 2012. There were 61 sets of comments, including comments from
approximately 149 different people from approximately 112 companies representing 9 of the 10
Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
Summary: The drafting team made the following revisions in response to comments:
TPL-002-1c: footnote b - It is recognized that Firm For purposes of this footnote, the following
are not counted as Firm Demand will be interrupted if it is: (1) Demand directly served by the
Elements removed from service as a result of the Contingency, orand (2) Interruptible Demand
or Demand-Side Management Load.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and
magnitude of Non-Consequential Load Loss following Contingency planning events.
TPL-001-2a: footnote 12 - 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.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand
interruption under footnote ‘b’ on the health, safety, and welfare of the community
Section II, Bullet #5. Future plans to mitigate alleviate the need for Firm Demand interruption
under footnote ‘b’
Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as
an element of a Corrective Action Plan in Year One of the Planning Assessment, the
Transmission Planner or Planning Coordinator must assure ensure that the applicable regulatory
authority authorities or governing bodybodies responsible for retail electric service issues does
not object to the use of Firm Demand interruption under footnote ‘b’ if either:

Section III, last paragraph: Once assurance has been received that the applicable regulatory
authority authorities or governing bodybodies responsible for retail electric service issues does
not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

A number of respondents continue to question the legality of the proposed standards. The general line
of thought in those comments is that NERC is imposing itself into the local planning process in violation
of existing statutes. The SDT does not believe that to be the case and has responded accordingly to
those commenters.
Many commenters questioned the use of a stakeholder process at all. Those commenters expressed
the opinion that the FERC Order did not mandate the use of the stakeholder process. The SDT used the
Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard;
not because it contained a stakeholder process, but because the process was not well defined, did not
include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure
that BES reliability would be maintained. The balloted draft added detail and specificity to the already
approved approach.
In addition, many commenters chose to question already approved facets of the proposed TPL-001-2a
standard. These commenters are questioning the application (or non-application) of footnote 12 for
various planning events. TPL-001-2 was previously approved by the industry and the NERC Board of
Trustees. The SAR for this project took that approval as the starting point for the specific discussion of
footnote ‘b’/12 and does not allow for review of previously approved applications of the footnote.
The SDT is requesting that the project be moved to a successive ballot.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11

2

Index to Questions, Comments, and Responses
1.

Do you agree with the text in the body of the footnote including the maximum capacity threshold?
If you do not support these changes or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestionsin your comments. For the
maximum capacity item, please supply any technical rationale for your comment along with
limiting conditions and any current criteria in use at your entity. ..................................................13

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of
Attachment 1? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ........................................................................................................................................46

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II
of Attachment1? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ........................................................................................................................................60

4.

Do you agree with the text in Section III of Attachment 1? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments............................................................................................76

5.

If you have any other comments on this Standard that you haven’t already mentioned above,
please provide them here: ............................................................................................................ 100

Consideration of Comments: Project 2010-11

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

Additional Member

Northeast Power Coordinating Council
Additional Organization

Region

Segment
Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Carmen Agavriloai

Independent Electricity System Operator

NPCC

2

3.

Greg Campoli

New York Independent System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC

5

8.

Kathleen Goodman

ISO - New England

NPCC

2

9.

Christina Koncz

PSEG Power LLC

NPCC

5

Consolidated Edison Co. of New York, Inc. NPCC

3

10. Peter Yost

2

3

4

5

6

7

8

9

10

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Michael Lombardi

Northeast Utilities

NPCC

1

12. Randy MacDonald

New Brunswick Power Transmission

NPCC

9

13. Bruce Metruck

New York Power Authority

NPCC

6

14. Silvia Parada Mitchell

NextEra Energy, LLC

NPCC

5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

16. Robert Pellegrini

The United Illuminating Company

NPCC

1

17. Si-Truc Phan

Hydro-Quebec Transenergie

NPCC

1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC

5

19. Brian Robinson

Utility Services

NPCC

8

20. Ben Wu

Orange and Rockland Utilities

NPCC

1

21. Wayne Sipperly

New York Power Authority

NPCC

5

22. Donald Weaver

New Brunswick System Operator

NPCC

2

2.

Group

Southwest Power Pool Reliability Standards
Development Team

Jonathan Hayes

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Jonathan Hayes

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

3. John Allen

City utilities of springfield SPP

1, 4

4. Don Taylor

Westar Energy

SPP

1, 3, 5, 6

5. Bo Jones

Westar Energy

SPP

1, 3, 5, 6

3.

Group

WILL SMITH

MRO NSRF

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

OPPD

MRO

1, 3, 5, 6

3.

TOM BREENE

WPS

MRO

3, 4, 5, 6

4.

JODI JENSON

WAPA

MRO

1, 6

5.

KEN GOLDSMITH

ALTW

MRO

4

6.

ALICE IRELAND

XCEL

MRO

1, 3, 5, 6

7.

DAVE RUDOLPH

BEPC

MRO

1, 3, 5, 6

8.

ERIC RUSKAMP

LES

MRO

1, 3, 5, 6

9.

JOE DEPOOTER

MGE

MRO

3, 4, 5, 6

2.

Consideration of Comments: Project 2010-11

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

10. SCOTT NICKELS

RPU

MRO

4

11. TERRY HARBOUR MEC

MRO

1, 3, 5, 6

12. MARIE KNOX

MISO

MRO

2

13. LEE KITTELSON

OTP

MRO

1, 3, 5

14. SCOTT BOS

MPW

MRO

1, 3, 5, 6

15. TONY EDDLEMAN NPPD

MRO

1, 3, 5

16. MIKE BRYTOWSKI GRE

MRO

1, 3, 5, 6

17. DAN INMAN

MPC

MRO

1, 3, 5, 6

4.

paul haase

Group

Seattle City Light

2

3

X

X

X

X

4

X

5

6

X

X

X

X

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. pawel krupa

seattle city light

WECC 1

2. dana wheelock

seattle city light

WECC 3

3. hao li

seattle city light

WECC 4

4. mike haynes

seattle city light

WECC 5

5. dennis sismaet

seattle city light

WECC 6

5.

Group

Greg Rowland

Duke Energy

Additional Member Additional Organization Region Segment Selection
1. Doug Hils

Duke Energy

RFC

1

2. Lee Schuster

Duke Energy

FRCC

3

3. Dale Goodwine

Duke Energy

SERC

5

4. Greg Cecil

Duke Energy

RFC

6

6.

Group

Chris Higgins

Bonneville Power Administration

Additional Member Additional Organization Region Segment Selection
1. Chuck Matthews

Transmission Planning

WECC 1

2. Berhanu Tesema

Transmission Planning

WECC 1

3. Melvin Rodrigues

Transmission Planning

WECC 1

7.

Group

Chris Pink

Tri-State G&T

X

Additional Member Additional Organization Region Segment Selection
1. Chris Pink
2. Mark Stein
3. Janelle Gill

Consideration of Comments: Project 2010-11

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

4. Bill Middaugh

8.

Group

Jim Kelley

Additional Member

SERC EC Planning Standards Subcommittee

Additional Organization
Ameren Services Co

SERC

1

2. Charles Long

Entergy Services

SERC

1

3. Edin Habibovich

Entergy Services

SERC

1

4. James Manning

NC Electric Membership Corp. SERC

1

5. Bob Jones

Southern Company Services

1

Group

X

Region Segment Selection

1. John Sullivan

9.

X

SERC

Scott Miller

MEAG Power

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Steve Grego

MEAG Power

SERC

5

2. Steve Jackson

MEAG Power

SERC

3

3. Danny Dees

MEAG Power

SERC

1

10.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

Tim Beyrle

City of New Smyrna Beach FRCC

4

2.

Jim Howard

Lakeland Electric

FRCC

3

3.

Greg Woessner

Kissimmee Utility Authority FRCC

3

4.

Lynne Mila

City of Clewiston

FRCC

3

5.

Joe Stonecipher

Beaches Energy Services FRCC

1

6.

Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

7.

Randy Hahn

Ocala Utility Service

FRCC

3

8.

Stan Rzad

Keys Energy Services

FRCC

1

11.

Group

David Dockery - NERC
Realiability Compliance
Coordinator
Additional Member

Associated Electric Cooperative, Inc. JRO00088

Additional Organization Region Segment Selection

1. Central Electric Power Cooperative

SERC

1, 3

2. KAMO Electric Cooperative

SERC

1, 3

3. M & A Electric Power Cooperative

SERC

1, 3

4. Northeast Missouri Electric Power Cooperative

SERC

1, 3

Consideration of Comments: Project 2010-11

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5. N.W. Electric Power Cooperative, Inc.

SERC

1, 3

6. Sho-Me Power Electric Cooperative

SERC

1, 3

12.

Group

Michael Jones

Additional Member
1. Michael Schiavone

13.

Additional Organization

Group

John Allen

Additional Member

Additional Organization

New York State Electric & Gas NPCC 1

8

9

X

ACES Power Marketing Standards
Collaborators
Additional Organization

X

Region

Segment
Selection

Sunflower Electric Power Corporation

SPP

1

2. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

3. Amber Anderson

East Kentucky Power Cooperative

SERC

1, 3, 5

4. John Shaver

Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.

WECC 1, 4, 5

5. Shari Heino

Brazos Electric Power Cooperative, Inc.

ERCOT 1, 5

6. Bob Solomon

Hoosier Energy Rural Electric Cooperative, Inc.

RFC

1, 3, 4, 5

Tim Ponseti, VP

TVA Transmission Reliability Engineering
and Controls

X

Individual

16.

Individual

Janet Smith

Arizona Public Service Company

17.

Individual

Antonio Grayson

Southern Company

X
X

18.

Individual

Western Area Power Administration

X

Individual

Brandy A. Dunn
Holly Rachel Smith,
Assistant General
Counsel

Individual

Thad Ness

Individual

Kenn Backholm

21.

7

X

1. Megan Wagner

20.

6

NPCC 1

Ben Engelby

Additional
Member

19.

5

Region Segment Selection

2. Raymond Kinney

15.

4

Region Segment Selection

Iberdrola USA

Central Maine Power

Group

3

Niagara Mohawk (A National Grid Company) NPCC 3

1. Joseph Turano

14.

X

National Grid

2

X
X
X

X
X

X
X
X
X

National Association of Regulatory Utility
Commissioners
American Electric Power
Public Utility District No.1 of Snohomish
County

Consideration of Comments: Project 2010-11

X

X

X

X

X

X

X

X

X

X

8

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

22.

Individual

X

Travis Metcalfe

Tacoma Power

Individual
24. Individual

Steven R. Wallace
Nazra Gladu

Seminole Electric Cooperative, Inc.
Manitoba Hydro

X

25.

Individual

James Tucker

Deseret Generation & Transmission

X

26.

Individual

Melissa Kurtz

X

23.

Individual

Chris Pink

USACE
Tri-State Generation & Transmission
Association

28.

Individual

Andrew Z. Pusztai

American Transmission Company

X

29.

Individual

John Collins

Platte River Power Authority

X

30.

Individual

Don Jones

Texas Reliability Entity

31.

Individual

Kirit Shah

Ameren

32.

Individual

Cheryl Moseley

Electric Reliability Council of Texas, Inc.

33.

Individual

David Kiguel

Hydro One Networks Inc.

X

34.

Individual

Martyn Turner

LCRA Transmission Service Corporation

X

35.

Individual

Joe Tarantino

Sacramento Municipal Utility District

X

36.

Individual

Patricia Robertson

BC Hydro and Power Authority

X

37.

Individual

Terry Harbour

MidAmerican Energy Company

38.

Individual

Andrew Gallo

Individual

Jason Marshall

City of Austin dba Austin Energy
New England States Committee on
Electricity (NESCOE)

Individual

Frederick R Plett

Massachusetts Attorney General

Individual
42. Individual

Richard Vine
Randy MacDonald

California Independent System Operator
NB Power Transmission

43.

Individual

Laurie Williams

Public Service Company of New Mexico

44.

Individual

RoLynda Shumpert

45.

Individual

Patrick Farrell

27.

39.
40.
41.

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

X

8

9

10

X
X

X

X

X
X

X

X

X

X

X

X

X
X
X
X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

South Carolina Electric and Gas

X
X

X
X

X

X

Southern California Edison Company

X

X

X

X

Consideration of Comments: Project 2010-11

7

9

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

46.

Individual

2

3

4

5

NBSO

Individual
48. Individual

Milorad Papic
Jack Stamper

Idaho Power Company
Clark Public Utilities

X

49.

Individual

Tom Hanzlik

SCE&G

X

50.

Individual

Kathleen Goodman

ISO New England

51.

Individual

Larry Watt

Lakeland Electric

X

52.

Individual

Chantal Mazza

Hydro Québec TransÉnergie

X

53.

Individual

Kayleigh Wilkerson

X

Individual

Mark Westendorf

Lincoln Electric System
Midwest Independent Transmission System
Operator, Inc.

55.

Individual

Dan Inman

Minnkota Power Cooperative

X

56.

Individual

Bob Casey

Georgia Transmission Corp

X

57.

Individual

Michael Falvo

Independent Electricity System Operator

58.

Individual

Richard Bachmeier

Gainesville Regional Utilities

59.

Individual

Spencer Tacke

Modesto Irrigation District

60.

Individual

Jason Weiers

Otter Tail Power Company

X

X

X

61.

Individual

Alice Ireland

Xcel Energy

X

X

X

54.

Consideration of Comments: Project 2010-11

7

X

Donald Weaver

47.

6

X

X
X

X

X

X

X

X

X

X

X
X
X
X

10

8

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: The SDT thanks you for your participation. Your support of comments from another organization has been
noted.
Organization

Supporting Comments of “Entity Name”

Seattle City Light

Puget Sound Energy

MEAG Power

Snohomish County Public Utility District

Associated Electric Cooperative, Inc. - JRO00088

SERC EC Planning Standard Subcommittee

USACE

MRO NSRF

MidAmerican Energy Company

MidAmerican supports the NSRF comments

City of Austin dba Austin Energy

Tacoma Power and Snohomish P.U.D.

South Carolina Electric and Gas

South Carolina Electric and Gas - SCE&G

Clark Public Utilities

Snohomish County PUD and Tacoma Power.

Lakeland Electric

FMPA

Consideration of Comments: Project 2010-11

11

Organization

Supporting Comments of “Entity Name”

Gainesville Regional Utilities

FMPA - Florida Municipal Power Agency

Otter Tail Power Company

Minnkota Power Cooperative

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1.

Do you agree with the text in the body of the footnote including the maximum capacity threshold? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. For the maximum capacity item, please supply any technical rationale for your comment along
with limiting conditions and any current criteria in use at your entity.

Summary Consideration: The majority of the comments received for this question were handled with explanations of the SDT intent or
clarifications of the constraints under which the SDT was working. There were a number of comments however concerning the
justification of the threshold values. The remand order from FERC requested that a Section 1600 data request be made to provide data
on the actual usage of footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a
maximum value for the amount of Load that could be planned to be shed under footnote ‘b’. DOE and other thresholds can be a point
of reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any
deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach.
There were several comments regarding the application of footnote 12 within Table 1 of proposed TPL-001-2a. Such discussion is out of
scope for this project as defined in the Standards Authorization Request (SAR). TPL-001-2 has been approved by the industry through
the standards development process and by the NERC Board of Trustees. Nothing in this project affects where footnote 12 is applied
within Table 1. The only change being proposed is to the details of how to utilize footnote 12 as shown in the proposed Attachment 1.
The following clarifications to language were made due to comments received:
TPL-002-1c: footnote b) It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load
Loss following Contingency planning events.
TPL-001-2a: footnote 12 - 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.
Organization

Yes or No

Consideration of Comments: Project 2010-11

Question 1 Comment

13

Organization

Yes or No

MRO NSRF

No

USACE

Question 1 Comment
(1) Change the wording at the end of the first sentence from “following
Contingency events” to “following Contingency events and Contingency
events during the planned (maintenance) outage of any bulk electric
equipment)”. This would remind Transmission Planners and Planning
Coordinators to include the consideration of planned outages at demand
levels for which the outage would be performed.
(2) Raise the maximum load dropping threshold for the footnote from 75
MW to 100 MW. A 100 MW threshold is reasonable because the DOE uses
the intentional dropping of more than 100 MW as one of the thresholds
for determininge when enough load is dropped to justify a formal system
event analysis.
(3) Add a sentence at the end of the footnote to read, “This footnote
does not apply to any load that is not NERC registered (e.g. load that does
not meet the greater than 25 MW NERC registration criterion).
(4) If a portion of the non-consequential load loss used to mitigate a
contingency is controllable by a demand side load management system,
can it be excluded from the “Firm Demand interruption” in TPL-002-1c
Table I footnote ‘b’ and/or “Non-Consequential Load Loss” in TPL-001-2a
Table 1 footnote 12? Does it have to be curtailed on a pre-contingent
basis in order to be excluded from the non-consequential load total, or
can it be excluded even if the curtailment happens through action of the
UVLS? Does this load count towards the 25 MW and 75 MW thresholds?
RECOMMENDATION: When describing “interruption of firm demand” or
“non-consequential load loss” in footnote ‘b’ add the language “not
counting load shed on a pre-contingent basis”. This would be added to the
last sentence of footnote ‘b’ if it indeed should not be counted towards
the 75 MW threshold. Similar language could be added in Attachment 1
Section III in regards to the 25 MW and 75 MW thresholds and in TPL-001-

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Yes or No

Question 1 Comment
2a as well. This would explain much more clearly what is counted towards
the two thresholds and decrease confusion.
(5) If multiple companies own portions of the non-consequential load loss
a used to mitigate a contingency at a single substation does each
company’s load portion count towards the 25 MW and 75 MW thresholds
or does the total load at the substation count? For example, 100% of the
load at a substation is set to trip with automatic UVLS. Company A, B, and
C own load amounts X, Y, and Z at the substation. Is the amount of load
counted towards the 25 MW and 75 MW thresholds X+Y+Z, or is each
counted separately?
RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote
‘b’ could read “In no case can the planned Firm Demand interruption from
under footnote ‘b’ exceed 75 MW from one entity.” Similar language
could be added in Attachment 1 Section III in regards to the 25 MW and
75 MW thresholds and in TPL-001-2a as well. This would explain much
more clearly what is counted towards the two thresholds and decrease
confusion.

Response: (1) The SDT intended the first sentence to be a fundamental statement of planning principle and thus believes that the
suggested wording is redundant and therefore not required. Consideration of planned outages at demand levels for which the
outage is performed is covered in proposed TPL-001-2a, Requirement R1 where it is stated that models must represent actual System
conditions as well as in Requirement R2, Part 2.1.3 which clearly states that analysis is to be done when known outages are
scheduled. No change made.
(2) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
(3) Load that is served from the entity’s transmission system is considered as applicable Load in this standard regardless of the
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Yes or No

Question 1 Comment

underlying registration situation. No change made.
(4) Proposed TPL-002-1c states in the footnote that: “It is recognized that Firm Demand will be interrupted if it is: (1) directly served
by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management
Load” (emphasis added). This makes it clear that Demand-Side Management Load is not to be considered as Non-Consequential
Load. In proposed TPL-001-2a, the proposed definition of Non-Consequential Load includes the term ‘Interruptible Load’ which as
defined in the NERC Glossary includes demand to be curtailed that the end-use customer makes available through contract or
agreement. Thus, the concept is covered in proposed TPL-001-2a as well. However, upon reviewing the comments, the SDT has seen
that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
(5) “Ownership” of the Non-Consequential Load Loss is not a relevant factor; all thresholds mentioned in the footnote are related to
the total Non-Consequential Load Loss. No change made.
ACES Power Marketing Standards
Collaborators

No

(1) We disagree with placing an upper limit on the amount of firm load
shed. Conceptually, it seems like a good idea but we do not believe that
such a threshold could ever consider all of the potential issues that could
arise and would cause the need to plan to shed firm load. This is
especially true considering that the SAR clarifies that the upper threshold
will be based on the existing planned load shedding values. Future issues
cannot be considered by the information contained in the data request.
Consider a situation in which a new transmission line was included in
Planning Assessment but cannot be built because right of ways cannot be
obtained. Should an upper limit be placed on planned load shed in such a
situation?
(2) We disagree with the threshold of 75 MW. In Order No. 762, the
Commission discussed the “blend concept,” where it “envisioned the
planner would consider up to 100 MW of planned Firm Demand
interruption along with other options to resolve the system performance

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Yes or No

Question 1 Comment
criteria violation and submit its documentation and explanation to the
entity deciding whether the planned load shed is acceptable.” (emphasis
added) Even the Commission envisioned using higher thresholds.
Furthermore, the data appears to show that one instance of NonConsequential Load Loss would be immediately out of compliance
because it is actual 75.2 MW not 75 MW. If the upper threshold is too
close to 75 MW, any load growth might also compel the instance to be
disqualified. If the SDT plans to keep the upper limit, we suggest
increasing the amount to at least 100 MW.

Response: (1) The SDT understands the problematic nature of future considerations in setting threshold values. However, the SDT
believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount of Load
planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No change made.
(2) The SDT believes that the threshold selected is consistent with the data supplied in the data request within reasonable limits.
Increasing the threshold to 100 MW is not consistent with the data supplied and the SDT believes that such an action would be
viewed as a non-acceptable least common denominator approach. No change made.
Minnkota Power Cooperative

No

Otter Tail Power Company

1. MPC QUESTION: If a portion of the non-consequential load loss used to
mitigate a contingency is controllable by a demand side load management
system, can it be excluded from the “Firm Demand interruption” in TPL002-1c Table I footnote ‘b’ and/or “Non-Consequential Load Loss” in TPL001-2a Table 1 footnote 12?
a. Would this load count towards the 25 MW and 75 MW thresholds?
b. Would it have to be curtailed on a pre-contingent basis in order to be
excluded from the non-consequential load total, or can it be excluded
even if the curtailment happens through action of the UVLS?
c. RECOMMENDATION: When describing “interruption of firm demand” or
“non-consequential load loss” in footnote ‘b’ add the language “not
counting load shed on a pre-contingent basis”. This would be added to the

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Yes or No

Question 1 Comment
last sentence of footnote ‘b’ if it indeed should not be counted towards
the 75 MW threshold. Similar language could be added in Attachment 1
Section III in regards to the 25 MW and 75 MW thresholds and in TPL-0012a as well. This would explain much more clearly what is counted towards
the two thresholds and decrease confusion.
2. MPC QUESTION: If multiple companies own portions of the nonconsequential load loss used to mitigate a contingency at a single
substation, does each company’s load count towards the 25 MW and 75
MW thresholds or does the total load at the substation count?
a. EXAMPLE: 100% of the load at a substation is set to trip with automatic
UVLS. Company A, B, and C own load amounts X, Y, and Z at the
substation. i. Is the amount of load counted towards the 25 MW and 75
MW thresholds X+Y+Z, or is each counted separately?
b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I
footnote ‘b’ could read “In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed 75 MW from one entity.” Similar
language could be added in Attachment 1 Section III in regards to the 25
MW and 75 MW thresholds and in TPL-001-2a as well. This would explain
much more clearly what is counted towards the two thresholds and
decrease confusion.

Response: (1) Proposed TPL-002-1c states in the footnote that: “It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load” (emphasis added). This makes it clear that Demand-Side Management Load is not to be considered as NonConsequential Load. In proposed TPL-001-2a, the proposed definition of Non-Consequential Load includes the term ‘Interruptible
Load’ which as defined in the NERC Glossary includes demand to be curtailed that the end-use customer makes available through
contract or agreement. Thus, the concept is covered in proposed TPL-001-2a as well. However, upon reviewing the comments, the
SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 1 Comment

Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
(2) “Ownership” of the Non-Consequential Load Loss is not a relevant factor; all thresholds mentioned in the footnote are related to
the total Non-Consequential Load Loss. No change made.
Iberdrola USA

No

“Contingency events” should be replaced by “Planning Events.”
Why would load shedding be limited only for certain circumstances in the
Near-Term Transmission Planning Horizon? The Near Term is likely the
period when the least can be done to avoid load shedding due to the time
required for permitting and construction of facilities.
A maximum capacity threshold is reasonable, whether 75 MW or a lower
value.

Response: The SDT agrees that ‘Contingency events’ should be replaced by ‘planning events’ in proposed TPL-001-2a where the
terminology in the performance tables uses ‘planning’ instead of ‘Contingency’. However, such a change is not warranted in proposed
TPL-002-1c where the ‘planning’ terminology was never used.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and magnitude of NonConsequential Load Loss following Contingency planning events.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. No change made.
Thank you for your support.
Massachusetts Attorney General

No

Although I voted for this Footnote, I do have concerns. 1) There is no
reliability benefit to the 75MVA threshold limit. There should be no limit
in the standard - it should be between stakeholders to decide that limit,
not nationally imposed.
2) Any such agreement to consider non-consequential losses should have
no impact to the BES especially when maintained in a confined boundary.

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Yes or No

Question 1 Comment
3) This takes away local decision making of PUC/ Local Board decision
making;
4) FERC's concern that a few entities would disguise the "stakeholder"
process to shed load is unfounded and should not be applied on a
continent-wide basis. FERC is trying to impose tighter standards than
the industry wants.

Response: (1) The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap
on the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order.
No change made.
(2) The SDT agrees that it normally should not have an impact. However, the purpose of the footnote is to ensure that it will not
have an impact. No change made.
(3) The SDT disagrees. The PUC/Local Board would typically be part of the “applicable regulatory authorities or governing bodies
responsible for retail electric service issues” shown in Attachment 1, Section I, Bullet 1. The same body would be expected to be the
entity involved in Attachment 1, Section III. Therefore, the PUC/Local Board would be a primary participant in the proposed process.
No change made.
(4) The conditions placed on the stakeholder process will provide consistency in the application of footnote ‘b’ on a continent-wide
basis. No change made.
Xcel Energy

No

Although the maximum capacity value is used for planning purposes, how
does this correlate with operational standards/issues that may require
that value be greater. The planning studies look at very specific seasonal
conditions on the system and may not necessarily look at all the states of
the transmission system during the normal business day. If an operational
event requiring a greater value of Non-Consequential Load Loss (NCLL) is
executed and the specific outage was not considered in a planning study,
how will this affect compliance with the planning standard.
There was no technical rationale by the SDT for selecting the maximum
value, thus a limit should not be set and should be left as a general

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Organization

Yes or No

Question 1 Comment
discussion issue in the Stakeholder Process due to the many unforeseen
issues that may arise.

Response: The commenter correctly points out that this is a planning standard. Operational standards have their own sets of
requirements. The proposed requirements for TPL-001-2a state that models utilized must reflect System conditions anticipated for
the period in question. If the planner has done this, there should be no question as to whether they are fulfilling the requirements of
the standard. No change made.
The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount
of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. The limit selected
was derived from the data received for the data request. Use of actual data is the technical rationale in the selection of the
threshold. No change made.
Electric Reliability Council of Texas, Inc.

No

As an initial matter, ERCOT does not believe the planning process should
allow for nonconsequential load shedding under single contingency
conditions. Accordingly, ERCOT takes no position on the proposed
maximum load shedding amount.
Even though the NERC BoT approved the Stakeholder Process, ERCOT
does not believe that the Stakeholder Process should be included as an
Attachment to a footnote to a reliability standard.
Also, there is an inconsistency in the terminology used in the footnotes
relative to the load shed - firm demand and non-consequential load are
both used. Non-consequential load is the correct term and the language
should be consistent.
Although it is ERCOT’s position that non-consequential load should not be
allowed to be shed under single contingency conditions from a planning
perspective, if the SDT elects to retain a vehicle for such exceptions, it
should establish objective, reliability based criteria that lend themselves
to inclusion in a reliability standard. This is consistent with the general
approach for reliability standards, which prescribe the "what", not the

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Yes or No

Question 1 Comment
"how". If the exceptions are based on objective criteria that are known
upfront, and those criteria reflect appropriate reliability based technical
justifications, then the risk of unwarranted exceptions to the general
prohibition due to misuse of the exception process is mitigated.
Furthermore, the exception process should be external to the NERC
Reliability Standards (e.g. in the Rules of Procedure), which should merely
reference authorized exceptions granted pursuant to that process.
With respect to the stakeholder process, in no case should a reliability
standard mandate a stakeholder process in any respect, procedural or
substantive. In ISO/RTO regions, stakeholder processes fall within
ISO/RTO governance matters. These issues are beyond the purview of
NERC Reliability Standards. In other regions, although the relevant
functional entities do not have stakeholder processes analogous to
ISOs/RTOs, any relevant processes are similarly beyond the scope of the
reliability standards.Accordingly, the SDT should eliminate all revisions
related to the establishment of a stakeholder process. As discussed in
response to question 5, FERC is not requiring this approach, but rather has
only provided guidance with respect to ways to possibly bring the prior
proposal in line with applicable regulatory approval standards for
reliability standards.
Additionally, as a general matter, substantive reliability standards
requirements should not be imbedded within a footnote to a
requirement. In this case, not only is there a substantive requirement
imbedded in the footnote, there is also a substantial attachment (which
must become part of the enforceable standard requirements}... and, to
make it worse, the attachment is an attachment to the footnote, rather
than an attachment to and referred to by a reliability standard
requirement.

Response: ERCOT is free to adopt a position of not allowing Non-Consequential Load shed in its reliability footprint. An entity can
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Question 1 Comment

always do more than the requirements stated. No change made.
The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it
contained a stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria
for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail
and specificity to the already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in
Reliability Standards and both mechanisms have been used before. No change made.
The SDT believes that the terminology is consistent. Non-Consequential Load is a newly defined term that only applies to proposed
TPL-001-2a. It is not appropriate to use this terminology in proposed TPL-002-1c which predates proposed TPL-001-2a. No change
made.
The SDT has set up criteria for consideration in the potential usage of footnote ‘b’ for planning purposes in Attachment 1, Section II,
Bullets 1 through 8. The criteria described are objective. The process describes what must be done to allow for the usage of footnote
‘b’ in the planning process. No change made.
The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it
contained a stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria
for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail
and specificity to the already approved approach. If the ISO/RTO has an existing process that meets the requirements, it is free to
use such process as stated in Attachment 1, Section I. No change made.
Footnotes and attachments are acceptable mechanisms for use in Reliability Standards and both mechanisms have been used before.
No change made.
National Association of Regulatory Utility
Commissioners

No

Consideration of Comments: Project 2010-11

As NARUC stated plainly in its Comments filed in FERC Docket No. RM1118 (Dec. 20, 2011), “not only does the law require that the States maintain
authority over distribution level reliability, States are in the best position
to guide load shedding so that it has the least negative impact on the
State’s customers and the operation of the local distribution system.” Id
at p. 4. Given the twin responsibilities of FERC to maintain bulk system
reliability and the states to ensure reliable and affordable service to retail
load, NARUC supports the portion of the standard that requires
notification and consultation with state and local regulators. However,
23

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Yes or No

Question 1 Comment
the maximum capacity threshold (set at 75 MW) is problematic. In this
instance, it appears that the 75 MW maximum capacity threshold is
merely a reflection of antidotal information from five data request
responders and as such is not technically justified. NARUC is not poised to
offer an alternative; given that the state/local regulator is consulted in
this process, the maximum capacity threshold should just be dropped.
States should be able to authorize an 80 MW exception, or whatever level
is reasonable, under specific circumstances if local economics and
reliability warrant it.

Response: The data request is not anecdotal information. All of the Transmission Planners in the continental United States supplied
their data in response to the data request. The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the
planning process without a cap on the amount of Load planned to be shed. The SDT also believes that such a position is consistent
with the wording in the Order. Given the participation of appropriate regulatory bodies in both Sections I and III, the SDT believes
that the current threshold is the best possible solution. No change made.
American Transmission Company

No

ATC recommends the following alternative language for both Footnote ‘b’
(Table 1 in TPL-002-1c [page 6]) and Footnote ‘12’ (Table 1 in TPL-001-2a
[page 14]:(1) Change the wording at the end of the first sentence from
“following Contingency events” to “following Contingency events for the
prior condition of all equipment in service or during the planned
(maintenance) outage of any bulk electric system equipment”. This would
remind Transmission Planners and Planning Coordinators to include the
consideration of planned outages at demand levels for which the outage
would be performed.
(2) In the last sentence of the footnote, raise the maximum load dropping
threshold for the footnote from 75 MW to 100 MW. A 100 MW threshold
is reasonable because the DOE uses the intentional dropping of more than
100 MW as one of the thresholds for determining when enough load is
dropped to justify a formal system event analysis.

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Question 1 Comment
(3) Add a sentence at the end of the footnote to read, “This footnote
does not apply to any load that is not NERC registered (e.g. load that does
not meet the greater than 25 MW NERC registration criterion).

Response: (1) Consideration of planned outages at demand levels for which the outage is performed is covered in proposed TPL-0012a, Requirement R1 where it is stated that models must represent actual System conditions as well as in Requirement R2, Part 2.1.3
which states that analysis is to be done when known outages are scheduled. No change made.
(2) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a least common denominator approach and would thus be rejected. No
change made.
(3) Load that is served from the entity’s transmission system is considered as applicable Load in this standard regardless of the
underlying registration situation. No change made.
Hydro Québec TransÉnergie

No

Dropping load in the general sense should not be endorsed, but it is
recognized that there are special situations where it cannot be avoided.
Provided there is no widespread, adverse effect on the reliability of the
interconnected BES, the effect of a firm demand interruption on
customers is under the purview of the applicable regulatory authority that
is responsible for local transmission and retail service over the load to be
curtailed, and the TPL standard should not put a limit at 75 MW.

Manitoba Hydro

No

Given that it is deemed that a stakeholder procress is required, there is no
rationale for a maximum level. The stakeholders are in the best position
to judge the appropriate level of allowable curtailment.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No

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Question 1 Comment

change made.
Florida Municipal Power Agency

No

Lakeland Electric
Gainesville Regional Utilities

FMPA has two issues:1. What is the technical justification for 75 MW?
There is no other metric in use similar to it. FMPA believes that, if the
stakeholder process reveals that the stakeholders are willing to accept
decreased service continuity to save money on their electric bills, why
should that be limited to 75 MW which has nothing to do with BES
reliability. BES reliability will not be impacted until load shedding gets
near to the largest single loss of source contingency in relation to supply /
demand mismatch. Other standards have chosen the low value of 300
MW as indicative, (e.g., CIP v5 for UFLS, EOP-004 for disturbance
reporting); hence, FMPA recommends that the maximum amount of load
shedding be 300 MW.
2. The footnote should also address a process whereby the transmission
customer agrees to conditional firm service if the Transmission Planner /
Transmission Service Provider (TSP) plans on curtailing firm service to that
customer following a single contingency. The TSP should not be able to
unilaterally degrade service from a state where it was not conditional to a
state where it is conditional.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. The
remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’ by
planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount of
Load that could be planned to be shed under footnote ‘b’. Other thresholds can be a point of reference or sanity check but in and of
themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the threshold derived
from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
An entity can always approach a customer to request to a change in the type of service provided, with or without the consideration
of footnote ‘b’ utilization. The institution of the formal process proposed here would bring the transmission customer into the
decision making process which makes any condition open and transparent and which may initiate discussions on service type as
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Question 1 Comment

referenced above. No change made.
Modesto Irrigation District

No

I am voting NO because there is no technical basis for use of the 75 and
25 MW absolute threshold values, regardless of the size of the utility's
load, referenced in the proposed standard. WECC's past experience with
implementation of arbitrary magnitudes for requirements (e.g., the 5%
and 7% arbitrary magnitude contingency reserve requirements), has
proved to be problematic. I would suggest investigating a technical basis
for using a relative requirement, such as percentage of the utility's load,
maybe 5% and 2.5%, respectively, and that it be based on technical
requirements similar to those found in Table 1 of the WECC Criteria TPL001-WECC-CRT-2.Thank you.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Utilizing a percentage of an entity’s Load may be
problematic – when dealing with a small entity it could be a small value but still of rather large import and if dealing with a large
entity could result in significant amounts of Load shed being planned. The FERC Order states that a percentage approach would not
be appropriate for the aforementioned reasons. The SDT believes that any deviation from the threshold derived from the actual data
may be viewed as a non-acceptable least common denominator approach. No change made.
Ameren

No

Consideration of Comments: Project 2010-11

It appears that a least common denominator approach was used to
develop the upper limit of 75 MW. Only 1 out of 18 respondents would
drop 75 MW of load, and only two respondents would drop 61-70 MW of
load. Our review of the data request responses concludes that only 22%
of the respondents that presently utilize footnote “b” would drop more
than 50 MW, and only 33% of the respondents that use footnote “b”
would drop more than 40 MW. The proposed 75 MW limit is too high and
is not supported by the responses to the data request. An upper limit of
40 MW is more appropriate, based on the data responses.

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Question 1 Comment

Response: Based on the comments received, the majority of the industry does not agree that a lower threshold would be
appropriate. The SDT does not believe that a least common denominator approach was utilized. The value selected is a reasonable
limit based on the data received, potential vagaries in future considerations, and undefined system configurations that may arise. No
change made.
MidAmerican Energy Company

No

MidAmerican supports NSRF comments with one change. The proposed
NSRF addition of “consideration of planned outages at demand levels for
which the outage would be performed” to the text of footnote “b” after
“following Contingency events” should not be added. If the addition is
made, a reasonable time frame clarification is necessary and should be
added such as “greater than 6 months”. The proposed change would then
read “consideration of planned outages greater than 6 months or longer
at demand levels for which the outage would be performed”.

Response: The SDT is not proposing to adopt the suggested change of the MRO NSRF. Please see the response to MRO NSRF above.
Midwest Independent Transmission System
Operator, Inc.

No

No. We believe footnote b in NERC TPL 002-1 and/or footnote 12 in TPL001-2 should be eliminated because the intent of these standards is not to
rely on non-consequential firm load shedding after a single contingency
event. However, if these footnotes are not eliminated, there should be
some limitation on how much firm load shed is allowed. We object to any
level higher than the proposed 75 MW level and would prefer a level
below 75 MW, but won’t object to the proposed 75 MW level if the
footnotes are not eliminated.

Response: The SDT believes that the wording of the footnote states that Non-Consequential Load shedding should not be the intent
but recognizes that particular circumstances may result in such a planned action. The 75 MW level is being retained. No change
made.
Duke Energy

No

Consideration of Comments: Project 2010-11

Regarding the maximum capacity item, we believe that 75 MW is much
too low. While Duke Energy has not historically used the footnote, setting
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Yes or No

Question 1 Comment
the upper limit at 75 MW raises a concern. An upper limit of 75 MW
severely limits the ability of a Transmission Planner to use the footnote.
The 75 MW limit appears to be the maximum reported in the survey. The
survey is a snapshot in time and to assume that there never have been
nor never will be situations where the correct decision of a Transmission
Planner and its stakeholders would be to exceed the 75 MW limit is
illogical. The 75 MW limit is likely to create a situation where a
Transmission Planner is forced to convert a network line to radial in order
to remain in compliance with the standard, to the detriment of reliability
to customers. The key to understanding use of the footnote is realizing
that, in most cases, using the footnote is extremely unlikely to result in
customer outages, because the probablility of the initiating contingency
occurring under conditions requiring additional load shed is very low. A
more reasonable upper limit would be the 300 MW limit that is
established as the threshold for DOE Disturbance Reporting. It is also
important to remember that no matter what upper limit is established,
Non-consequential Load Loss of 25 MW or greater cannot be included in
Year One of the Planning Assessment if the applicable regulatory authority
or governing body responsible for retail electric service issues objects.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southern California Edison Company

No

Consideration of Comments: Project 2010-11

SCE believes that the maximum capacity threshold should be increased
from 75 MW to 250 MW, as 250 MW is the limit utilized by the California
Independent System Operator (CAISO) for a consequential load drop for a
single contingency. The CAISO has a rigorous transmission planning

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Question 1 Comment
process that allows it to plan for and permit load shedding up to 250 MW.

Response: The footnote only applies to Non-Consequential Load Loss. Upon reviewing the comments, the SDT has seen that
Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Arizona Public Service Company

No

The 75 MW threshold is too low. No technical justification has been given
for choosing 75 MW. It should be a significantly higher value for TPL-002.
Currently AZPS does not use non-consequential load dropping to meet
any standard but this option should be preserved. There could be times
when alternate to the load dropping would be building a new
transmission line costing hundreds of millions of dollar for a very low
probability scenario of high load conditions. The threshold value should
be 100 MW or more.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Northeast Power Coordinating Council

No

Consideration of Comments: Project 2010-11

The 75MW of Firm Demand interruption is retail load that is being
dropped. Dropping load in the general sense should not be endorsed, but
it is recogn ized that there are special situations where it cannot be
avoided. If a regulator responsible for retail load is comfortable with
greater than 75MW being dropped in a rare situation, there should not be
a requirement to build out of the situation. Provided there is no
widespread, adverse effect on the reliability of the interconnected BES,
the effect of a firm demand interruption on customers is under the
purview of the applicable regulatory authority that is responsible for local
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Question 1 Comment
transmission and retail service over the load to be curtailed.
There is no technical basis for the 75MW figure. It was included as a
result of a Section 1600 Data Request, and is an arbitrary value. There
should not be a limit without a technically supportable reliability based
reason.

National Grid

No

The 75MW of Firm Demand interruption is retail load that is being
dropped. Dropping load in the general sense should not be endorsed, but
it is recognized that there are special situations where it cannot be
avoided. If a regulator responsible for retail load is comfortable with
greater than 75MW being dropped in a rare situation, there should not be
a requirement to build out of the situation. Provided there is no
widespread, adverse effect on the reliability of the interconnected BES,
the effect of a firm demand interruption on customers is under the
purview of the applicable regulatory authority that is responsible for local
transmission and retail service over the load to be curtailed.
There is no technical basis for the 75 MW figure with respect to reliability
impact. Although, the value was developed by the SDT as a result of their
review of Section 1600 Data Request, there was no reliability based
analysis performed to identify whether the 75 MW is reasonable number.
It is possible that a number either larger or lower could be identified if a
reliability and cost-effective analysis is conducted.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No
change made.
The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’
by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount
of Load that could be planned to be shed under footnote ‘b’. All of the Transmission Planners in the continental United States
supplied their data in response to the data request. The SDT believes that any deviation from the threshold derived from the actual
Consideration of Comments: Project 2010-11

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Yes or No

Question 1 Comment

data may be viewed as a non-acceptable least common denominator approach. No change made.
ISO New England

No

The draft footnote states that interruption “is limited to circumstances
where the Non-Consequential Load Loss meets the conditions shown in
Attachment 1.” Attachment 1 appears to impermissibly require State
participation in federal transmission planning processes. Further, it places
the ERO in a Transmission Planning role, which exceeds the limits of the
ERO’s functions under Section 215 of the Federal Power Act. The current
language appears to conflict with (1) federal statutes that are clear that
wholesale electric transmission issues are matters of federal, and not
state, jurisdiction, (2) orders of the Federal Energy Regulatory Commission
(“FERC”) regarding the role and independence Regional Transmission
Organizations (“RTOs”) with regard to transmission planning, and (3)
Section 215 which limits NERC’s authority to regulate “users, owners and
operators” of the Bulk-Electric System. Further, the conditions appear to
conflict with Section 215 of the Federal Power Act by placing the ERO in a
transmission planning role and providing it with regulatory or functional
oversight regarding the substance of transmission planning decisions. The
ERO has the authority to develop and enforce standards, but is not a
transmission planning entity and does not have the authority to substitute
its judgment for registered Planning Authorities and Transmission
Planners regarding the planning or operation of the bulk power system.
Where a review is sought of planning entities’ determinations, per FERCfiled Tariffs, they may be brought before FERC under Section 206 of the
Federal Power Act. Because the footnote, and the associated Attachment
appear to be in conflict with FERC Tariff and other statutory provisions,
they should be removed.
The footnote itself states, “An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency events.” The objective statement within the

Consideration of Comments: Project 2010-11

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Question 1 Comment
standard does not appear to create a requirement and should be
removed.

Response: The SDT does not believe that the footnote violates any regulations concerning transmission planning since there is no
federal process as cited in the comment. The proposed process simply brings stakeholders, including local regulators, to the table in
an open and transparent manner while setting criteria for when footnote ‘b’ can potentially be utilized. The ERO is not participating
in the planning process. The role of the ERO is restricted to a determination of whether the planned utilization of footnote ‘b’ will
cause an Adverse Reliability Impact to the BES. The ERO has no further role in the transmission planning process beyond that
determination. No change made.
The SDT believes that the objective statement referenced is an important consideration in the over-all planning process and thus
should be retained. It sets the over-all tone and approach that should be followed. No change made.
Deseret Generation & Transmission

No

The limitation of Non-Consequential load loss to the 25 MW-75 MW level
with a hard limit at 75 MW is arbitrary and give no deference to the cost
of the cure. In the West the high cost of a fix may not be in the public
interest. The 75 MW hard high limit should be replaced with a soft 75
MW limit but allowing higher levels if the governing body or regulatory
authority approves it.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes it is
unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a hard cap on the amount of Load planned
to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No change made.
New England States Committee on
Electricity (NESCOE)

No

Consideration of Comments: Project 2010-11

The New England States Committee on Electricity (NESCOE) appreciates
the opportunity to comment on NERC’s proposed revisions to
Transmission Planning (TPL) Reliability Standards relating to permissible
applications of planned load interruption. NESCOE is New England’s
Regional State Committee and is governed by a board appointed by the
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Question 1 Comment
six New England Governors. These comments reflect the collective view
of the six New England states.The issue of planned, limited load
interruption rests at the central intersection of cost and reliability. It
illustrates the fundamental balance that Commissioner Norris details in
Order No. 762: the tradeoffs between “increasing levels of reliability and
the costs that come along with achieving them.” Transmission Planning
Reliability Standards, Order No. 762, 139 FERC ¶ 61,060 (April 19, 2012)
(Norris, Comm’r. concurring in part and dissenting in part) at 2. NESCOE
agrees with Commissioner Norris that, as a general matter, this balancing
should translate to a more explicit consideration of costs in the NERC
standard development process. Id. at 1. The language in footnote “b”and corresponding footnote 12 of TPL-001-2-implicitly recognizes cost
considerations in transmission planning by tolerating limited load
shedding under defined circumstances. NESCOE offers below comments
and suggestions in response to the SDT’s questions. These responses
reflect NESCOE’s interest in planning for a robust bulk electric system
while taking into account the magnitude of risk that a solution is intended
to address and the costs associated with competing solutions.
NESCOE appreciates the work of the SDT in attempting to respond to the
Commission’s directives and the time constraints under which the SDT
was required to make changes to footnote “b.” However, NESCOE is
concerned that establishing a bright-line maximum capacity threshold
that is an absolute ceiling is overly prescriptive and unnecessary to meet
the Commission’s directives. In Order 762, the Commission rejected the
contention that regional stakeholder processes should unilaterally
determine the appropriate criteria to apply in planning to interrupt firm
load. Order 762 at P 32. However, provided that technical parameters
are in place, the Commission stated that it would be “amenable” to
regional stakeholders establishing such criteria if, for example, NERC or
the applicable Regional Entity “developed an exception process that

Consideration of Comments: Project 2010-11

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Question 1 Comment
provides flexibility in decisions based” on their expert view of regional
considerations. Id. The SDT’s proposal, however, would impose a onesize-fits-all requirement that forecloses a regional discussion of the
quantitative and qualitative considerations that may justify an exception
to the proposed 75 MW maximum capacity value. Such a regional
discussion in ongoing in New England. In 2010, ISO New England
introduced to stakeholders a draft Transmission Planning Load
Interruption Guideline. The Guideline noted that load interruption should
not be the principal tool to address transmission system reliability
violations and highlighted the priority of reliable service. However,
applying quantitative and qualitative criteria, the Guideline proposed for
stakeholder discussion various levels of controlled load interruption in N1-1 conditions-potentially up to hundreds of megawatts-that may be
tolerated under clearly defined conditions. NESCOE did not take a view of
the Guideline when it was presented for review and does not do so here.
For now, the Guideline remains in draft form following stakeholder
comment in 2011. However, imposition of a maximum capacity threshold
that is an absolute ceiling for N-1 events and potentially, through revisions
to footnote 12, N-1-1 events, would prematurely limit important regional
discussions of this issue. A better approach, and one which the
Commission appears amenable, would be to accompany any bright-line
value with an exception process. There is recent precedent supporting
such an approach: NERC proposed changes to its Rules of Procedure to
accommodate exceptions to the proposed 100 kV bright-line Bulk Electric
System definition.
Separately, the footnote references Attachment 1 to the respective
planning standards, which requires a stakeholder process review of the
utilization of planned interruption. Such review is only triggered if
utilization is sought in the Near-Term Transmission Planning Horizon, even
though the footnote permits utilization of load interruption throughout

Consideration of Comments: Project 2010-11

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Question 1 Comment
the planning horizon. NESCOE does not support this limiting language,
which is at tension with an open and transparent planning process over
the entire planning horizon. The term “Near-Term” should be stricken or
further justification should be provided.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes it is
unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount of Load planned to be
shed. The SDT also believes that such a position is consistent with the wording in the Order. The SDT believes that the referenced
exception process is what is being proposed. The proposed process sets up an open and transparent process for allowing such Load
shed in specific conditions and with specific limitations. Any future revisions to footnote 12 will be accomplished through the
approved standards development process and any discussion on changing threshold values would be part of that process. No change
made.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as mandatory for the
Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but does not limit its
use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission Planning Horizon
situations in its individual stakeholder processes is left to the entity to determine. No change made.
Sacramento Municipal Utility District

No

There is no reliability benefit with an establish MW threshold.
Implementing any threshold is descriptive and the standard should depict
an outcome not the means of the outcome.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No
change made.
Public Utility District No.1 of Snohomish

No

Consideration of Comments: Project 2010-11

We believe the survey significantly underestimated the use of NonConsequential Load Shedding because the survey asked about past usage
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Yes or No

County
Tacoma Power
MEAG Power
City of Austin
Clark Public Utilities

Question 1 Comment
of footnote b under Version 001, not about planned load shedding in TPL
version 002 or the proposed footnote 12. TPL version 002 added several
new contingencies, and also changed the Non Consequential Load
shedding applicability for several contingencies.
We have 4 specific concerns, followed by several suggested edits: 1)
Analyzing the contingencies “P1.4 Loss of a Shunt Device” and “P2.1
Opening of a line section w/o a fault” are new requirements that will lead
to increased use of footnote 12. It is common on fringes of the
interconnected system to have weak sources. Significant utility
investment will be redirected to remediate these fringe performance
issues due to the P2.1 and its associated restrictions for firm load
shedding and no RAS or UVLS mitigation. This is a low probability and low
impact to the main grid contingency with a high mitigation cost, given the
new mitigation restrictions.
2) Contingencies “P2.2 Bus Section fault” and “P2.3 Internal Breaker
Fault” were previously defined as category “C multiple contingencies”
with the restriction that the Firm Load shedding must be
planned/controlled. However Version 002 no longer allows dropping
nonconsequential load for EHV but removes all restrictions for HV load
shedding. Since these contingencies result in opening the same breakers
as category P1 contingencies, the use of footnote 12 should be consistent
with P1.
3) Contingencies P3.1-P3.4 were previously defined as category “C
multiple contingencies” with Firm loading shedding allowed. In version 2,
these contingencies have been changed from allowing planned load
shedding to only allowing Non-Consequential load shedding per footnote
12. Although this does not directly impact our utility, the survey results
do not include utilities using “must-run” generation.
4) As demonstrated by multiple questions at the last webinar, many

Consideration of Comments: Project 2010-11

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Question 1 Comment
utilities do not understand the definition of Non-Consequential Loads, and
therefore may not have correctly reported the usage of NonConsequential Load Shedding. The v2 changes cascade to the unfortunate
conclusion that UVLS and RAS are no longer permitted as cost effective
transmission performance mitigation, despite new low probability
contingencies that drive performance problems at the edges of the
network.
-Proposed changes: A) Change the maximum amount from 75 MW to 300
MW. Several other standards including CIP have a strong technical basis
for selecting 300 MW as the maximum limit for load shedding programs.
B) Footnote 12 on contingency 2.1 should be replaced with a new
footnote 15 that reads “ 15. For this contingency, load which is served
radial from a remaining single source line may be shed as if it were
Consequential Load.” This change would acknowledge that while P2.1
does involve just one element, the likelihood of occurrence is similar to
bus section faults, so the resulting system performance requirements
should be similar.
C) The first two sentences of footnote 12 should be deleted. Remove the
first sentence because it is general in nature and is a basic tenant of any
load-serving utility. Remove the second sentence because column 7 of
Table 1 explicitly states where Non-Consequential Load Loss is allowed.
D) The third sentence of footnote 12 should have the words “under
footnote 12” added. Without this addition, all Non Consequential Load
Loss including the allowed loss for P4, P5 and P6 would still be subject to
Appendix 1. The revised sentence would read “When Non-Consequential
Load Loss is used under footnote 12 within the Near-Term ...”

Response: The SDT could not reasonably request data for unknown future conditions. The only viable mechanism for data input was
the data request as it was formulated.
Consideration of Comments: Project 2010-11

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Question 1 Comment

1) The SDT disagrees that planning events P1.4 and P2.1 are ‘new’ requirements in proposed TPL-001-2a. These requirements were
previously approved by the industry and NERC Board of Trustees. No change made.
2) The SDT disagrees that P2.2 and P2.3 planning events will open the same breakers as P1 planning events. For the EHV planning
events cited, the standard approved by the industry and the NERC Board of Trustees accepted a raising of the bar by not allowing
Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the application of the
footnote. No change made.
3) For the P3.1 – P3.4 planning events, the standard approved by the industry and the NERC Board of Trustees accepted a raising of
the bar by not allowing Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the
application of the footnote. No change made.
4) Discussion of the proposed definition of Non-Consequential Load was provided during the various postings of proposed TPL-0012. The SDT has received no comments from other utilities regarding confusion over the definition. Single Contingencies are not
low probability events. No change made.
A) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value
for the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as the 300 MW referenced
above can be a point of reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter.
The SDT believes that any deviation from the threshold derived from the actual data may be viewed as a non-acceptable least
common denominator approach. No change made.
B) For planning event P2.1, the standard approved by the industry and the NERC Board of Trustees accepted a raising of the bar by
not allowing Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the application
of the footnote. No change made.
C) The SDT believes that such statements are important to set the tone and approach to be taken with the planning standards. No
change made.
D) The SDT agrees and has made the suggested clarification.
TPL-001-2a: footnote 12 - 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.
Independent Electricity System Operator

No

Consideration of Comments: Project 2010-11

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
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Question 1 Comment
no adverse effect on the reliability of the interconnected bulk power
system, the effect on customers of a firm demand interruption is the
responsibility of the applicable regulatory authority or its agencies
responsible for local transmission and retail service over the load to be
curtailed.We propose replacing the sentence, in the footnote and in
attachment one, section III that reads:”In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is
a Canadian Entity (or a Mexican Entity) should be implemented in a
manner that is consistent with/or under the direction of the Applicable
Governmental Authority or its agency in Canada (or Mexico).

Hydro One Networks Inc.

No

Consideration of Comments: Project 2010-11

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected bulk
electric system, the effect on customers of a firm demand interruption is
the responsibility of the applicable regulatory authority or its delegated
agencies responsible for local transmission and retail service over the load
to be curtailed.If it is decided to proceed with the 75 MW or any other
value, we propose replacing the sentence, in the footnote and in
attachment one, section III that reads:”In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a non-US Registered Entity
should be determined by the applicable Regulatory Authority or
Governmental Authority or its delegated agency in that is responsible for
retail electric service issues in that jurisdiction.”

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Question 1 Comment

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
NB Power Transmission

No

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected bulk
electric system, the effect on customers of a firm demand interruption is
the responsibility of the applicable regulatory authority or its delegated
agencies responsible for local transmission and retail service over the load
to be curtailed.

NBSO

No

We do not agree with setting a MW limit for non-consequential load loss.
The allowable amount should be determined and approved by the
jurisdiction of the area(s) whose load is affected. The intent of the TPL
standard and this footnote is to ensure that if non-sequential load loss is
accounted for or relied up to ensure BES reliability (as assessed in the
planning horizon), that such a decision needs to be approved by the
appropriate jurisdiction. Non-consequential load loss being applied or
considered to achieve BES reliability in planning assessment is in itself not
a BES reliability concern that rises up to a continent-wide reliability
standard.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as 300 MW can be a point of reference
or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation
from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No
change made.

Consideration of Comments: Project 2010-11

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Yes or No

Western Area Power Administration

No

Question 1 Comment
We do not support a maximum threshold of 75 MW or any MW level. It is
not appropriate to enforce a one size fits all maximum value. There are
no apparent reliability benefits from implementing a capacity loss
limitation...why not pick 300 MW?
Also we are not sure what prompted the additional distinction of allowing
the load shedding only in the near-term planning horizon...please
elaborate.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as 300 MW can be a point of
reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any
deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach.
No change made.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. No change made.
Platte River Power Authority

No

We do not support a maximum threshold. 1) It is not appropriate to
enforce a one size fits all maximum value that might unnecessarily overburden some communities.
2) The public process proposed in this standard provides significant
transparency from the transmission utilities and opportunity for
community input to decisions that will impact both the community's
reliability and rates.
3) Leave the maximum capacity threshold decisions to local regulatory
commissions and Boards of Directors.

Response: (1) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage
of footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value
Consideration of Comments: Project 2010-11

42

Organization

Yes or No

Question 1 Comment

for the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
(2) Thank you for your support.
(3) The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the
amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. Local
regulators are involved in the process through the wording in Attachment 1, Sections I and III. No change made.
California Independent System Operator

No

While we have voted in favor of supporting the changes to the footnote
and to move forward with the adoption of the standard, we remain
concerned that there is not a good foundation for concluding that loss of
load over 75 MW poses a reliability risk to the system compared to some
higher MW threshold. Instead, the 75 MW capacity threshold is simply
based on the current maximum planned loss of Non-Consequential Load.
While we support minimizing reliance on Non-Consequential Load Loss,
there may be scenarios where such reliance is unavoidable in the nearterm, and therefore may be needed until capital upgrades can be put in
place. At a minimum, the footnote or standard should provide for an
exception process, should it be necessary for a planned NonConsequential Load Loss of greater than 75 MW.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes that the
referenced exception process is what is being proposed. The proposed process sets up an open and transparent process for allowing
such Load shed in specific conditions and with specific limitations. No change made.
Tri-State Generation & Transmission
Association

No

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Organization

Yes or No

LCRA Transmission Service Corporation

No

Question 1 Comment

Response: Without a specific comment, the SDT is unable to respond.
TVA Transmission Reliability Engineering
and Controls

Yes

TVA agrees with the general text; however, TVA believes that the 75 MW
limit is too low. TVA believes that a better limit would be 100 MW - which
is the amount for load shedding required to be reported under OE-417
under emergency operational policy. This would allow some future load
growth as well as any possible new loads that may develop quickly in
which a utility may not have time to complete necessary projects in a
corrective action plan.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southwest Power Pool Reliability Standards
Development Team

Yes

Bonneville Power Administration

Yes

SERC EC Planning Standards Subcommittee

Yes

Associated Electric Cooperative, Inc.
Southern Company

Yes

American Electric Power

Yes

Seminole Electric Cooperative, Inc.

Yes

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Public Service Company of New Mexico

Yes

Idaho Power Company

Yes

SCE&G

Yes

Lincoln Electric System

Yes

Georgia Transmission Corp

Yes

Question 1 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11

45

2.

Do you agree with the description and components of the Stakeholder Process in Section I of Attachment 1? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: There was little or no commonality in the comments submitted and the responses are mainly statements
clarifying SDT intent as shown in the individual responses.
The following change was made due to industry comment:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Organization

Yes or No

Southern Company

No

The complex stakeholder process described in Attachment 1 should be required
only if the amount of planned load shed exceeds 25 MW or the contingency is
greater than 300 kV. Since the average use given in the survey was 19 MW and
there is no evidence of harm to the BES reliability resulting from that use, there is no
good reason to require such a stakeholder process for amounts less than 25 MW.
The stakeholder process should only be required for larger amounts of load.

SCE&G

No

No, We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

TVA Transmission Reliability
Engineering and Controls

No

TVA recommends that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting

Consideration of Comments: Project 2010-11

Question 2 Comment

46

Organization

Yes or No

Question 2 Comment
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

SERC EC Planning Standards
Subcommittee

No

Associated Electric Cooperative

We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

Response: The SDT disagrees that the proposed process is complex or unnecessary. The SDT used the Board of Trustees approved
standard as a starting point for this draft. FERC remanded the standard; not because it contained a stakeholder process, but because
the process was not well defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and
did not assure that BES reliability would be maintained. The balloted draft added detail and specificity to the already approved
approach. The SDT believes that all uses of footnote ‘b’ should go through the stakeholder process. No change made.
Seminole Electric Cooperative,
Inc.

No

#1.It is unclear what factors must be met in order to be an affected stakeholder
under the Stakeholder Process in Attachment 1? This process appears to be devoid
of any objective factors that can assist an entity in determining whether a party is a
stakeholder or not. NERC should define what an “affected stakeholder” is or list
factors to assist industry in making such a determination.
#2.In Standard TPL-002-1c, Attachment 1, Section I. “Stakeholder Process,” there
was a section added at the end of this subsection that is three lines in length. This
section states that a stakeholder process does not need to be repeated unless there
has been a “material change.” It is clear from the latest webinar presentation on
this Project that this language is not “clear and unambiguous”. NERC does not
present any metrics, whether qualitative or quantitative, to guide industry as to
when a material change occurs to an application of footnote ‘b.’ Without any
metrics to guide industry, it is bewildering that NERC reasons that entities will
consistently interpret what a material change constitutes. Therefore, SECI believes
that this provision is in conflict with the NERC Rules of Procedure and FERC Order

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 2 Comment
762.
#3.In Standard TPL-002-1c, Attachment 1, Section I. “Stakeholder Process,” the
requirement that the process “shall be documented” was deleted from the first
paragraph. It does not appear to be reasonable that a process that is not written,
nor known to any stakeholder, meets the common understanding of “open and
transparent.” Seminole believes that the requirement that the process be
documented and that documents be available to potential affected parties be
reinstated into the Standard.

Response: 1. The SDT believes that the planning entity is in the best position to identify affected stakeholders and that any attempt
to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a one size
fits all approach. No change made.
2. The SDT believes that the planning entity has the best understanding of when a change would become material. With the large
range of design philosophies and geographic difference between the entities within NERC, it is not practical to adopt a single one size
fits all approach. In addition, since the use of footnote ‘b’ will be a part of the entity’s Corrective Action Plans, interested
stakeholders will have the opportunity to question the continued use of footnote ‘b’. No change made.
3. The SDT believes the ‘documented’ terminology is unnecessarily redundant since the entity must be able to demonstrate
compliance to its Compliance Enforcement Authority. It should not be necessary to mandate that an entity has to document a
process. No change made.
NBSO

No

(1) The process presented in Section I of Attachment I is overly prescriptive. This
Section needs only to stipulate that the proposed utilization of the footnote be
reviewed through an open and transparent stakeholder process developed and/or
approved by the jurisdiction (a Regional Entity or regulatory authority) of the area(s)
whose load is affected area.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself should not explicitly restrict its utilization to only the Near-Term horizon.
Often, in the long-term planning horizon, when approval for transmission addition

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 2 Comment
or reinforcement cannot be obtained for whatever reasons, utilization of the
footnote is considered and adopted, subject to stakeholder’s and regulatory
authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year 0ne) time frame and hence the proposed
provision does not allow for utilizing the footnote for the interim period before new
or reinforced transmission facilities are put in place. We suggest removing the word
“Near-Term”.

Response: (1) FERC remanded the standard because they wanted the stakeholder process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
The balloted draft added the indicated detail and specificity to the already approved approach. No change made.
(2) Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can
be interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as mandatory for
the Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but does not limit
its use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission Planning Horizon
situations in its individual stakeholder process is left to the entity to determine. No change made.
ACES Power Marketing Standards No
Collaborators

(1) Many RTOs have well organized stakeholder processes that could be utilized to
satisfy Attachment 1. Because the TPL standards apply to both the PC and TP, one
may conclude that both functions need to have a stakeholder process. Rather, we
think that the TP should be able to rely on its PC’s stakeholder process. We
recommend clarifying Attachment 1 that it is acceptable for the TP to rely on the
PC’s process and that both entities are not required to have redundant processes.
The most important point is that stakeholders have an opportunity to participate.

Response: The SDT believes that it has covered this possibility in the revised language posted for this draft allowing an entity to use
an existing process as long as it meets the criteria. Such usage is not restricted to a particular entity and as long as each entity is able
to demonstrate that it meets the items in Section I, entities can share the same process. No change made.
Minnkota Power Cooperative

No

Consideration of Comments: Project 2010-11

1. MPC QUESTION: In Attachment 1 Section I, what is the definition of a

49

Organization

Yes or No

Otter Tail Power Company

Question 2 Comment
“stakeholder”?
a. Is this intended to apply to multiple NERC functional entities (DP, TO, TOP, LSE),
public residential customers, and/or business owners that are affected by system
contingencies?
b. RECOMMENDATION: Define stakeholder to be “affected Transmission Owners,
Transmission Operators, Distribution Providers, and Load-Serving Entities.” We
believe it is most appropriate for the Transmission Owners, Transmission Operators,
Distribution Providers, and Load-Serving Entities to objectively evaluate the risks of
load shedding in a local area against the cost impact of a large transmission project
on the rate base.
2. MPC QUESTION: In Attachment 1 Section I item 1, what does “including
applicable regulatory authorities” refer to?
a. Is this the same body that “applicable regulatory authority or governing body”
refers to in Section III?
b. Are these requirements still applicable if the 25 MW threshold in Section III is not
passed?
c. RECOMMENDATION: Attachment 1 Section I Item 1 could read “... including
applicable regulatory authorities or governing bodies responsible for retail electric
service as described in Section III. A clearly defined statement allows the
Transmission Planner and Planning Coordinator to identify the appropriate parties
to be included in every instance Attachment 1 is used.

Response: 1. The SDT believes that affected stakeholders should include the list of NERC functional entities and others. Transmission
customers, Planning Coordinators, Transmission Planners, and regulatory authorities with retail jurisdiction should typically be
included. The SDT believes that the planning entity has the best understanding of who an affected stakeholder will be and that any
attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a
one size fits all approach. No change made.

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 2 Comment

2. a. Yes, it is the same as those in Section III.
b. Yes, these requirements are applicable for each circumstance of planned use of footnote b. The SDT believes that the use of the
stakeholder process is necessary each time that an entity utilizes footnote b.
c. The SDT did not accept your recommendation. The SDT believes that the suggested change may be too limiting since it refers to a
single governing body. No change made.
Western Area Power
Administration

No

A public process seems out of place in a reliability standard.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
Manitoba Hydro

No

A stakeholder process should not be required in jurisdictions where a legislation
already authorizes interruptions, as consent of stakeholders cannot override
legislation.

Response: The SDT does not believe that the consent of stakeholders will override legislation. The proposed process provides an
opportunity for affected stakeholders, including regulators, to have the necessary information to fully understand the impacts of the
planned use of footnote b. If the applicable regulator does not object to the planned use of footnote b, it may be used. No change
made.
Iberdrola USA

No

“Stakeholders” is undefined - would this be the same stakeholder body identified in
the planning process of the Open Access Transmission Tariff?

Response: In many instances, the affected stakeholders would be the same stakeholders identified in the Open Access Transmission
Tariff planning process. However, the SDT believes that the planning entity has the best understanding of who an affected
stakeholder will be and that any attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to
the necessity of having to adopt a one size fits all approach. No change made.

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Public Utility District No.1 of
Snohomish County

No

MEAG Power
City of Austin
Clark Public Utilities
Tacoma Power

Question 2 Comment
In the first sentence, remove the words “as an element of a Corrective Action Plan.”
There are cases on the fringes of the system where Non-Consequential Load Loss is
the preferred alternative in both the long term and short term, not as a temporary
patch. Requiring the stakeholder process as part of Corrective Action Plan implies
that using footnote 12 cannot be the long term choice. Since a Corrective Action
Plan is a “list of actions and an associated timetable for implementation to remedy a
specific problem,” using this term removes the stakeholders ability to evaluated the
costs and benefits and instead requires them to treat this a problem where the only
solution is building new facilities.

Response: The stakeholder process is not required as part of a Corrective Plan. What the attachment states is that use of the
footnote cannot be part of the Corrective Action Plan unless it has gone through the process. And the SDT disagrees that inclusion of
this language ever requires a construction solution. Bullet #7 in Section II requires that alternatives to Load shed be presented for
process participants to see as well as providing the rationale for not selecting those alternatives. Cost and benefits can certainly be
part of this rationale. No change made.
Ameren

No

It is our opinion that that the stakeholder process should be conducted at least once
every five years if non-consequential load is planned to be dropped as part of the
Corrective Action Plan to meet single contingency events. If conditions have not
materially changed since the last review, this information should still be
communicated to the stakeholders.

Response: The SDT did not want to present repetitive information and unduly burden the planning entity or the stakeholder in this
process. However, an entity can always do more than what is required in the standard. No change made.
Tri-State Generation &
Transmission Association

No

NERC Functional Model definitions for Planning Authorities and Transmission
Planners do not include the types of activities being proposed in “Attachment 1.”
How is it appropriate to mandate to functional entities functions that are outside
those defined in the NERC functional model?

Response: The NERC Functional Model is a guideline for activities required of cited functional entities. It is periodically updated as
Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 2 Comment

conditions change. While the activities mentioned in the standard may not be explicitly spelled out in the NERC Functional Model,
the SDT does not believe that they are out of scope for either a Planning Coordinator or a Transmission Planner. No change made.
New England States Committee
on Electricity (NESCOE)

No

NESCOE appreciates the efforts of the SDT in developing a stakeholder process for
considering the use of load interruption in system planning. NESCOE especially
appreciates the heightened role accorded to states in light of jurisdictional issues
raised by the prospect of shedding load and implications for retail customers.
States must be intimately involved in weighing reliability considerations against the
economic implications of alternative approaches. Regarding the language in Section
I, see the comments above regarding striking “Near-Term” in this context.
NESCOE also suggests that additional clarity is needed regarding the intended
meaning of “applicable regulatory authorities or governing bodies responsible for
retail electric service issues.” This language potentially implicates state agencies
beyond public utility commissions (e.g., state consumer advocates, attorneys
general) and could create confusion for state agencies as well as transmission
planners that are required to provide notice to such entities and, pursuant to
Section III, provide a process for regulatory review. Instead, the SDT should revise
the language to read “electric retail regulatory authorities,” a term with clear
meaning that the Commission has itself used. See, e.g., Order 719.

Response: Please see the response to question 1.
The SDT believes that there may be instances where other regulatory bodies may want to be involved in the stakeholder process.
The SDT disagrees that the proposed language will create confusion for state agencies or transmission planners. The SDT believes
that the planning entity has the best understanding of who an affected stakeholder will be and that any attempt to codify a list of
such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a one size fits all approach.
No change made.
Independent Electricity System
Operator

No

Consideration of Comments: Project 2010-11

No. The process presented in Section I is overly prescriptive. If a section that
prescribes the principles of a stakeholder process is required, then for Canadian
entities this section should simply state that any threshold should be established in

53

Organization

Yes or No

Question 2 Comment
a manner consistent with other service levels that apply to local transmission and
retail service for the load to be curtailed.
Corrective action plans can rarely be implemented in a one-year time frame, and in
some cases, limited use of Non-consequential Load Loss will be preferable to
unaffordable transmission enhancements, therefore we believe that the use of
footnote ‘b’/’12’ should not be limited to the Near-Term Transmission Planning
Horizon. We propose that the phrase “the Near-Term Transmission Planning
Horizon of” be deleted from the opening paragraph.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
The SDT agrees that it may be difficult to implement construction options in a one year time frame and that the limited use of NonConsequential Load Loss may be an acceptable option. Footnote ‘b’ is not limited to Year One or to the Near-Term Transmission
Planning Horizon since the footnote recognizes that Firm Demand can be interrupted throughout the entire planning horizon. As
drafted, the standard defines the stakeholder process as mandatory for the Near-Term Transmission Planning Horizon since there
may not be time to implement other corrective actions but does not limit its use in the Long-Term Transmission Planning Horizon.
How individual entities reflect the Long-Term Transmission Planning Horizon situations in its individual stakeholder process is left to
the entity to determine. No change made.
Midwest Independent
Transmission System Operator,
Inc.

No

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our
comments under Question 5.

Response: Please see response to question 5.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT's response to Question 1 - stakeholder processes are not
appropriate for NERC standards.

Response: Please see response to question 1.

Consideration of Comments: Project 2010-11

54

Organization

Yes or No

Public Service Company of New
Mexico

No

Question 2 Comment
PNM voted yes to the Standard as a whole but would like the SDT to consider the
following concern: Part II.2.b of Attachment 1 that requires an assessment of the
effect of the use of Non-Consequential Load Loss under Footnote B on the health,
safety, and welfare of the community, and PNM believes that assessments of this
nature are entirely subjective and will be difficult to comply with and even more
difficult to audit. It is our belief that this criteria should be removed from the
Standard prior to its ultimate submittal to NERC.

Response: The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action
should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment A description of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
NB Power Transmission

No

The process in Attachment 1 is overly prescriptive. Attachment 1, if retained, needs
only to stipulate that the proposed utilization of the footnote be reviewed through
an open and transparent stakeholder process in compliance with the applicable
regulatory authority oversight.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
Hydro One Networks Inc.

No

The process presented in Section I is overly prescriptive. If a section that prescribes
the principles of a stakeholder process is required, then for non-US entities this
section should simply require that the process must be approved by the applicable
Regulatory Authority or Governmental Authority or its delegated agency that is
responsible for local transmission and retail service for the load to be curtailed in
that jurisdiction.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 2 Comment

within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
LCRA Transmission Service
Corporation

No

Response: Without specific comments, the SDT is unable to respond.
Xcel Energy

Yes

The possibility of NCLL is always present, whether in the planning or operational
arena. Section I (#5) should however specifically state that in the dispute resolution
process a stakeholder does not have right of refusal for NCLL. This should be
especially true when a transmission project has been proposed and NCLL in the
interim is required due to the regulatory process, equipment lead time, etc.
preventing the completion of project at an earlier time.

Response: Bullet #5 does not require specific attributes of the dispute resolution process. The SDT believes that the attributes of the
stakeholder process should be defined by the entity during the development of the stakeholder process. No change made.
MRO NSRF

Yes

USACE
MidAmerican Energy Company

(1) In Attachment 1 Section I, what is the definition of a “stakeholder”? Which NERC
functional entities would be included (TO, TOP, LSE)? Are the public residential
and/or business owners that are affected included in the definition? Some parties
may assume that local government representatives or residential or business
owners are included as stakeholders. We believe it is most appropriate for the
Transmission Owners, Transmission Operators, and Load-Serving Entities to
objectively evaluate the risks of load shedding in a local area against the cost impact
of a large transmission project on the rate base. RECOMMENDATION: Define
stakeholder to be “affected Transmission Owners, Transmission Operators, and
Load-Serving Entities.”
(2) In Attachment 1 Section I item 1, what does “including applicable regulatory
authorities” refer to? Is this the same body that “applicable regulatory authority or
governing body” refers to in Section III? Are these requirements still applicable if the

Consideration of Comments: Project 2010-11

56

Organization

Yes or No

Question 2 Comment
25 MW threshold in Section III is not passed? RECOMMENDATION: Attachment 1
Section I Item 1 could read “... including applicable regulatory authorities or
governing bodies responsible for retail electric service issues as described in Section
III. A less vague statement allows the important parties to be included in every
instance Attachment 1 is used.

Response: (1) In many instances, the affected stakeholders would be the same stakeholders identified in the Open Access
Transmission Tariff planning process. However, the SDT believes that the planning entity has the best understanding of who an
affected stakeholder will be and that any attempt to codify a list of such stakeholders in the proposed standards could lead to errors
due to the necessity of having to adopt a one size fits all approach. No change made.
(2) The term applies to any applicable, interested regulatory authority and is not necessarily the same body as mentioned in Section
III. Conversely, the regulatory body cited in Section III would certainly be one of the regulatory bodies referred to in Section I. If the
result of Section I is that the entity is not going to move forward with the plan, then Section III will never occur. No change made.
Texas Reliability Entity

Yes

Attachment 1, section I (Stakeholder Process) should be clarified to specify which
‘responsible entity’ needs to utilize or develop a transparent stakeholder process.
For example, if a contingency event in Entity A’s system causes Entity B to have to
shed non-consequential firm load to meet the BES performance requirements,
which Entity is responsible for ensuring the required review? TRE proposes adding
the following sentence to the first paragraph to assign responsibility for this type of
scenario: “The Planning Coordinator or Transmission Planner accountable for the
contingency event will be responsible for implementing the stakeholder process and
regulatory review.”

Response: The SDT believes that the current terminology is clear in that it is the entity that plans to utilize the footnote that needs to
initiate the process. No change made.
California Independent System
Operator

Yes

Consideration of Comments: Project 2010-11

There is no basis to support only allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment. The footnote itself
should not explicitly restrict its utilization to only the Near-Term horizon. Often, in
the long-term planning horizon, when approval for transmission addition or
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Organization

Yes or No

Question 2 Comment
reinforcement cannot be obtained for a variety of reasons, utilization of the
footnote is considered and adopted, subject to stakeholder’s and regulatory
authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year One) time frame and hence the proposed
provision does not allow for utilizing the footnote for the interim period before new
or reinforced transmission facilities are put in place. We suggest to remove the word
“Near-Term”.

Response: Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm
Demand can be interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as
mandatory for the Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but
does not limit its use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission
Planning Horizon situations in its individual stakeholder process is left to the entity to determine. No change made.
Southern California Edison
Company

Yes

The Stakeholder Process in Section I of Attachment 1 is similar to the method
effectively used by the CAISO to manage and incorporate stakeholder input in its
annual transmission planning process.

Platte River Power Authority

Yes

Although these descriptive steps for a public process seem out of place in a
reliability standard, Section 1 is in line with the planning principles of FERC Order
890.

Southwest Power Pool Reliability
Standards Development Team

Yes

Duke Energy

Yes

Bonneville Power Administration

Yes

Florida Municipal Power Agency

Yes

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Yes or No

Arizona Public Service Company

Yes

American Electric Power

Yes

Deseret Generation &
Transmission

Yes

American Transmission Company

Yes

Massachusetts Attorney General

Yes

Idaho Power Company

Yes

ISO New England

Yes

Georgia Transmission Corp

Yes

Modesto Irrigation District

Yes

Question 2 Comment

Response: Thank you for your support.

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3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of Attachment1? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Most of the commenters asked questions about the intent of the SDT in particular areas and the SDT has
provided individual responses accordingly.
There was one major overriding concern about Section II, Bullet 2b on the assessment on public health and safety. The SDT has clarified
its intent and also pointed out that the action required for this bullet item is analogous to what is already required in approved EOP-0012.1b.
Some commenters also questioned the use of the term ‘mitigate’ in Section II, Bullet 5. The SDT has clarified this language.
The following clarifying changes have been made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health,
safety, and welfare of the community
Section II, Bullet #5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Organization

Yes or No

TVA Transmission Reliability
Engineering and Controls

No

Question 3 Comment
TVA would like to propose that this Stakeholder process be postponed in the event
that a transmission fix for a load drop issue was already planned within the next 2 or
3 years. Thus the stakeholder process would only occur for projects that had no fix
planned within the next couple of years.
TVA is also not sure how to satisfactorily address “health, safety, and welfare of the
community” - TVA would appreciate some guidance on how to properly address
this.

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Question 3 Comment
TVA believes that item 1.b of Section II could contain CEII information and should
have limited distribution. The appropriate non-disclosure agreements would need to
be developed to prevent widespread publication of the information.

Response: ‘The SDT believes that the stakeholder process should occur whenever footnote ‘b’ is proposed to be utilized. The
construction option in later years will be a part of the information provided in the stakeholder process for review. In this case, there
will only need to be one review through the stakeholder process, if there are no material changes before the construction option is
completed. No change made.
The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action should be
analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect that
information while still providing the basics of the information needed for the process to continue. No change made.
ACES Power Marketing Standards No
Collaborators

(1) Adding the word “effect” on the health, safety, and welfare of the community
creates more confusion regarding what is needed for the assessment. We
recommend removing the effect clause from Section II.
(2) We disagree that the Transmission Planner should be required to provide an
assessment at all on the health, safety and welfare of the community. Attachment
1, Section 2a identifies the types of customers that are impacted without needing a
formal assessment. Stakeholders will have an opportunity to provide information
on impacts of planned load shedding through either the Transmission Planner’s
stakeholder comment process or through the local regulatory agency’s stakeholder
comment process. Further, these planned interruptions of firm demand are
expected to be short in nature so any impact would be de minimis. Finally, an
assessment on the health, safety and welfare of the community is an unnecessary
burden on the registered entity and is better suited for local governments that can
speak through the stakeholder process.

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Question 3 Comment
(3) Bullet 3 is based on available historical information. While this seems
reasonable, we have concerns because of the rare instances that Non-Consequential
Load Shed actually occurs. If a TP uses Non-Consequential Load Shed for the first
time, there is no historical information. What would be an acceptable basis for the
first use of Non-Consequential Load Shed when the entity is without historical
information?
(4) Expected time duration of the planned load shed is too speculative and should
not be required because any duration will likely be a guess. When actual
contingencies occur, the time of restoration varies and any time that was selected
prior to the event is not likely to be correct. We do not see the value in predicting
the duration time because there is too much uncertainty about how long an outage
will really last. The SDT needs to clarify what is expected for the duration of the
planned load shed.
(5) While we appreciate that the response to our comments clarified the intent is
that “Possible future plans could include a decision not to mitigate the need for Firm
Demand interruption,” the language in the Attachment simply does not reflect this.
The Attachment specifically states “Future plans to mitigate the need for NonConsequential Load Loss.” A decision not to mitigate the need for Firm Demand
interruption is not a future plan to mitigate. Consequently, Attachment 1, section
II.5 will need to be modified to implement this intent. Otherwise, this language is
certain to be interpreted as requiring a mitigation plan.

Response: (1) and (2) The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this
action should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
(3) Historical performance is not limited to Contingencies which result in Non-Consequential Load Loss. The estimated frequency
should be based on an entity’s average historical performance of similar Facilities applied to the specific Element being evaluated. No
change made.
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Question 3 Comment

(4) The expected duration could be a range of values based on various assumptions. In the planning environment the entity should be
able to analyze the situation and determine an expected duration for which an interruption would be in place. No change made.
(5) The SDT agrees and has changed the language accordingly.
5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Minnkota Power Cooperative

No

1. MPC QUESTION/COMMENT: In Attachment 1 Section II item 2b, “Assessment of
the effect ... on the health, safety, and welfare of the community” is vague.
Clarification is requested.a. RECOMMENDATION: Remove Item 2b because it
requires the assessment of the footnote application impact on the potential health,
safety, and welfare of the community. These types of assessments should be
eliminated because they are not electric system reliability matters and were not
stipulated by FERC. In the event that the Standards Development teams choses to
keep item 2b, then add language semi-defining this as follows in Attachment 1
Section II Item 2b “...health, safety, and welfare of the community as determined by
impact on critical health and emergency services.” This allows the Transmission
Planner and Planning Coordinator to identify the appropriate parties affected by the
contingency to be analyzed in every instance Attachment 1 is used.

American Transmission Company

No

ATC recommends the following change in Section II of Attachment 1 applicable to
both standards TPL-002-1c [page 8] and TLP-001-2a [page16]:Remove Item 2b
altogether because it requires the assessment of the footnote application impact on
the potential health, safety, and welfare of the community. These types of
assessments should not be required in the Standards because they are not electric
system reliability matters and were not stipulated within the FERC Order762.

Bonneville Power Administration

No

BPA does not support including information under Section II.2.b, an assessment of
the use of Non-Consequential Load Loss on the health, safety, and welfare of the
community. It would be nearly impossible for a planner to predict this in a future
case since it is hard to predict what loads will actually materialize in the future. In
addition, this information does not support reliability of the BES since reliability of

Otter Tail Power Company

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Yes or No

Question 3 Comment
the transmission system is assessed by meeting required technical performance for
certain contingencies and under certain conditions.

Arizona Public Service Company

No

Item 2b: Reference to health, safety, and welfare is unnecessary. All demand
interruption are going to have some impact on health, safety, and welfare. The
impact is subjective and will simply result in unnecessary study reports by
consultants and will act as a road block.

Iberdrola USA

No

Regarding the documentation required for item 2.b, how are “health, safety, and
welfare of the community” to be assessed? What are the metrics? How would
compliance with this provision be evaluated?

MRO NSRF

No

Remove Item 2b because it requires the assessment of the footnote application
impact on the potential health, safety, and welfare of the community. These types
of assessments should be eliminated because they are not electric system reliability
matters and were not stipulated by FERC.

Southern California Edison
Company

No

SCE participates in the rigorous CAISO annual transmission planning process that
considers the information included in the proposed Section II of Attachment 1.
However, the proposed language in Section II.2.b. “Assessment of the effect of Firm
Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community,” seems overly broad and confusing. The California Public Utility
Commission (CPUC) and CAISO presently consider these items before approving
transmission plans. It is unclear what type of information would be required in order
to meet the seemingly broad request contained in Section II.2.b. SCE believes that
the language of Section II.2.b. should be removed from Attachment 1, or
alternatively, the language should be revised to specifically exempt critical loads,
such as hospitals, fire department facilities, law enforcement facilities, and
correctional facilities.

Public Utility District No.1 of

No

We suggest removing section 2b “Assessment...health, safety...” for three reasons:

MidAmerican Energy Company
USACE

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Yes or No

Snohomish County

1)All outages have a negative impact on the community. Outages under footnote 12
do not inherently have more significant impact per MWhr lost than other outages
allowed per Table 1. By requiring additional analysis for a similar societal impact,
this provision discriminates against utilities at the fringes of the system. 2) While
reminding planners to consider that their decisions do have real impacts to real
people is a laudable goal, including this provision opens the door to significant legal
liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place
to introduce such a significant requirement. The Adequate Level of Reliability Task
Force would be a more appropriate venue for this idea.

MEAG Power
Clark Public Utilities

Tacoma Power

Question 3 Comment

No

City of Austin

We suggest removing section 2b “Assessment...health, safety...” for three reasons:
1)All outages have a negative impact on the community. Outages under footnote 12
do not inherently have more significant impact per MWhr lost than other outages
allowed per Table 1. By requiring additional analysis for a similar societal impact,
this provision discriminates against utilities at the fringes of the system. 2) While
reminding planners to consider that their decisions do have real impacts to real
people is a laudable goal, including this provision opens the door to significant legal
liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place
to introduce such a significant requirement. The Adequate Level of Reliability Task
Force would be a more appropriate venue for this idea.

Response: The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action
should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
Tri-State Generation &
Transmission Association

No

Consideration of Comments: Project 2010-11

In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that
the end-use customer makes available to its Load-Serving Entity via contract or
agreement for curtailment.” The process described in Attachment 1 creates an
agreement between stakeholders (aka “end-use customers”) and their transmission
providers. Thus, if the process described in Attachment 1 is followed, the “Firm
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Question 3 Comment
Demand” referenced would be reclassified as “Interruptible Demand.” In essence,
“Footnote b” does not allow the interruption of Firm Demand. It merely requires
that if interruption of Demand is required, it can only be Interruptible Demand. If
this was the intention of FERC, NERC, and the Drafting Team, why didn’t the drafting
team just state “Interruption of Firm Demand is not allowed”?

Response: Upon reviewing the comments, the SDT has seen that a clarification for Demand that is not included as Firm Demand for
footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Independent Electricity System
Operator

No

No. The process presented in Section II is overly prescriptive. If a section that
prescribes the information requirements for a stakeholder process is required, then
for Canadian entities this section should simply state that any threshold should be
established in a manner consistent with other service levels that apply to local
transmission and retail service for the load to be curtailed.

Hydro One Networks Inc.

No

The process presented in Section II is overly prescriptive. If a section that prescribes
the information requirements for a stakeholder process is required, then for non-US
entities this section should simply require that the process information
requirements must be in accordance with the requirements of the applicable
Regulatory Authority or Governmental Authority or its delegated agency that is
responsible for local transmission and retail service in that jurisdiction.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
Midwest Independent
Transmission System Operator,

No

Consideration of Comments: Project 2010-11

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our

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Inc.

Question 3 Comment
comments under Question 5.

Response: Please see response to question 5.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT's response to question 1-the NERC Reliability Standards should
not contain requirements related to stakeholder processes, whether they are
procedural or substantive. If an exception process is retained, it should be outside of
the NERC Reliability Standards (e.g. in the Rules of Procedure). To the extent the
proposed standard inappropriately retains the stakeholder related aspects, ERCOT
also provides the following comments on Section II-the ERCOT comments are in
parentheses for easy reference and distinction relative to the proposed
requirements.II. Information for Inclusion in Item #3 of the Stakeholder ProcessThe
responsible entity shall document the planned use of Firm Demand interruption
under footnote 'b' which must include the following: (ERCOT COMMENT: This is all
that is needed for this. The documentation would be relative to the objective
criteria developed for this purpose.)
1. Conditions under which Firm Demand interruption under footnote 'b' would be
necessary:a. System Load level and estimated annual hours of exposure at or above
that Load levelb. Applicable Contingencies and the Facilities outside their applicable
rating due to that Contingency(ERCOT COMMENT: "1" is not necessary if objective
criteria are developed as benchmarks for the exception process. In that case,
exceptions would only be allowed if the objective criteria were met, regardless of
the underlying assumptions related to conditions and contingencies.)
2. Amount of Firm Demand MW to be interrupted with:a. The estimated number
and type of customers affectedb. Assessment of the effect of the use of Firm
Demand interruption under footnote 'b' on the health, safety, and welfare of the
community(ERCOT COMMENT: The considerations reflected in a and b are
inappropriate for a reliability standard. Appropriate considerations for reliability
standards are related to the reliability performance of the system. The
considerations in a and b are more akin to quality of service issues better suited for

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Yes or No

Question 3 Comment
regional policy discussions. It is not within the purview of the SDT to address those
matters.)
3. Estimated frequency of Firm Demand interruption under footnote 'b' based on
historicalPerformance (ERCOT COMMENT: Historical performance is irrelevant. If
the SDT is going to retain revisions that accommodate non-consequential load
shedding, then the only relevant metrics are the objective criteria that set the
benchmarks for such exceptions.)
4. Expected duration of Firm Demand interruption under footnote 'b' based on
historical performance(ERCOT COMMENT: See ERCOT response to "3" above.)
5. Future plans to mitigate the need for Firm Demand interruption under footnote
'b'(ERCOT COMMENT: This is redundant to the requirement in the reliability
standards that requires a plan to resolve any violations identified in the planning
process.Furthermore, if load shedding is allowed, this requirement doesn't make
sense. Presumably the idea behind allowing these exceptions is to obviate the
prospective need for other alternatives. If that is not the case, then there is no need
to allow the exceptions, because the transmission upgrades to mitigate the need for
load shedding can be established in the planning horizon.)
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 'b'(ERCOT COMMENT: The basis for the load
shedding exception is to provide a means to meet the TPL performance
requirements in the context of a planning assessment. Accordingly, this is redundant
to the planning assessments, the point of which is to identify and resolve
performance issues.)
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote 'b'(ERCOT COMMENT: Load shedding
exceptions should be based on objective criteria and be reviewed pursuant to a
process external to the NERC reliability standards. Alternative discussions could be
part of that external process.)

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Yes or No

Question 3 Comment
8. Assessment of potential overlapping uses of footnote 'b' including overlaps with
adjacent Transmission Planners and Planning Coordinators(ERCOT COMMENT: It is
not clear what this means. Each functional entity performs assessments relative to
its own system. This appears to introduce a vague regional transmission planning
requirement with no structure or rules for such assessments.)

Response: Please see response to question 1.
The SDT believes that the criteria in Section II are objective and represent the information that a stakeholder will want to see for
assistance in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve
some parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
The SDT has revised the language of bullet #5 due to other comments received.
5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Bullet #8 does not introduce a regional planning requirement. It is consistent with Requirement R8 in proposed TPL-001-2a that
mandate sharing of Planning Assessments. No change made.
Xcel Energy

No

Section II should be left as part of the resolution in the dispute process and should
not be made a requirement. Some in particular include:§ II.1. - this should be
based only on applicable contingencies or conditions that could require NCLL.
Having to include the estimated hours at or above a load level may not always be
the most effective way to convey why NCLL will be used and adds little to the
argument of why or why not it needs to be used.
§ II.2.a - This may not always be apparent to the TO serving a wholesale
transmission customers (REC, MUNICIPAL, etc.). This should be eliminated since it
does little in emphasizing the need for NCLL.
§ II.2.b - The "effect" of the use of NCLL may not always be apparent, because it is
a perceived condition of what could happen that can be interpreted differently. I
agree that it should be mentioned in the Stakeholder process outlining the locations

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Question 3 Comment
where NCLL will take place and let the dispute process identify and assess the
health, safety and welfare of the community. How do you assess the effect in the
Planning of NCLL. The effect should be identified by the party being affected and
resolved in the dispute process.
§ II.3 & 4. - This needs to be eliminated. Expected frequency and duration of NCLL
based on historical performance DOES NOT GUARANTEE future performance and
does little in emphasizing the need for NCLL.
II.8 - This should be addressed by the Regional Planning Authority in their regional
studies.

Response: The SDT disagrees and believes that the criteria in Section II represent the information that a stakeholder will want to see
for assistance in determining their position on proposed planned actions. The SDT reminds the commenter that this process will
involve some parties that are not experts in interpreting assessments and that these parties will need information that may be
considered redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change
made.
ISO New England

No

Consideration of Comments: Project 2010-11

Section II, 2.a states that studies must address the estimated number and type of
customers affected by Non-Consequential Load Shedding. This language should be
removed for three reasons.(1) This appears to be inappropriate for a reliability
standard. The specific number and type of customers within a set number of MWs
that are electrically acceptable do not impact the reliability of the bulk electric
system (as defined by Section 215 of the Federal Power Act). (2) Even if the number
and type of affected customers were an appropriate process question for an ERO
standard, the number and type of customers may change depending on particular
system configuration at the time of the load shedding. For example, a substation
may be reconfigured to address other system issues such as maintenance and a
certain number of MWs of load being interrupted, while still electrically acceptable
from a system reliability perspective, may impact different numbers and types of
customers. (3) Assuming that the number and type of customers affected were an
appropriate metric, the Transmission Planner in many cases will not be the
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Question 3 Comment
appropriate entity to address these concerns. The Transmission Owner, Distribution
Provider or Load Serving Entities would be the appropriate entities to address
customer affects.
Section II, 2.b should be revised to delete the reference to “health, safety, and
welfare of the community.” It is inappropriate for a NERC Standard to require
planners to address the “health, safety, and welfare of the community.” NERC’s
authority appears limited to regulating the “reliability” of the bulk electric system.
Section 215 specifies that NERC’s authority it to establish Reliability Standards
necessary to ensure an “adequate level of reliability.” Reliability Standards may
specify the “design of planned additions or modifications to such facilities to the
extent necessary to provide for reliable operation.” Section 215 defines “reliable
operation” as “operating the elements of the BPS within equipment and electrical
system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure of system
elements.” Establishing this requirement is also arbitrary, because it is
inconsistent with other transmission planning requirements. For example, the same
load could be shed directly as the consequence of a fault and no such assessment is
required. In addition, Transmission Planners can plan for the shedding of radial load
with no assessment of health, safety and welfare.
Section II, requirements 3 and 4 discuss estimating frequency and duration of NonConsequential Load Loss based on historical performance. This provision is
inconsistent with the manner in which transmission system planning is conducted
and should be removed. The transmission system planning process uses
deterministic not probabilistic assessments. While a power system may utilize these
factors in assessing where the use of non-consequential load loss may be acceptable
in terms of providing service, these factors do not inform reliability risks to the bulk
electric system where the loss of load is found to be electrically acceptable in terms
of system reliability (i.e., no thermal, voltage, or stability issues are created or

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Question 3 Comment
exacerbated and no instability, uncontrolled separation, or cascading failures result).

Response: The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance
in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some
parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
The SDT understands the concerns and has clarified the wording. The intent of the SDT is that this action should be analogous to that
required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance in
determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some parties
that are not experts in interpreting assessments and that these parties will need information that may be considered redundant or
superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
SCE&G

No

We believe that item 1.b of Section II may contain Critical Energy Infrastructure
Information (CEII) and should have limited distribution. The appropriate nondisclosure agreements would be required in order to prevent widespread
publication of the information.

SERC EC Planning Standards
Subcommittee

No

We believe that item 1.b of Section II would contain CEII information and should
have limited distribution. The appropriate non-disclosure agreements would need to
be developed to prevent widespread publication of the information.

Associated Electric Cooperative

Response: If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect
that information while still providing the basics of the information needed for the process to continue. No change made.
NBSO

No

Consideration of Comments: Project 2010-11

We do not agree with the need for Section II (and Attachment I as a whole) at all.
The footnote, or Attachment I, should only stipulate that when Non-Consequential
Load Loss is needed to ensure that BES performance requirements are met, then
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Question 3 Comment
regulatory approval from local jurisdiction needs to be provided with demonstration
that the approval was obtained through an open stakeholder process.

Response: The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance
in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some
parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
LCRA Transmission Service
Corporation

No

NB Power Transmission

No

Response: Without specific comments, the SDT is unable to respond.
Texas Reliability Entity

Yes

In Section II, part 1b, TRE suggests replacing ‘applicable rating’ with ‘steady state
performance requirments’, to account for all the BES performance requirements (in
particular, steady-state and post-contingency voltages) for which the footnote may
be utilized.

Response: Applicable ratings are the basis for the performance requirements in Table 1 of proposed TPL-001-2a. Therefore, the SDT
believes that the existing terminology correctly addresses the performance issue. No change made.
Southwest Power Pool Reliability
Standards Development Team

Yes

In this section the reference to Customers should only be Customers of Transmission
and not open ended for any customer. Once it is sold wholesale the TP wouldn’t
know where it is being sent to. We would also note that under some jurisdictions
that there is a minimum duration threshold for keeping historical data on some of
these events that are being requested under this section. Need to add language to
accommodate these thresholds so as not to contradict what is being asked for by
the regulatory bodies.

Response: The SDT disagrees that the only customers that should be considered are wholesale customers. The total number of
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Question 3 Comment

customers affected is information that helps other stakeholders understand the full impact of the planned usage of footnote ‘b’. The
SDT also disagrees that the Transmission Planner will not know where the Load will be lost. The Transmission Planner cannot
evaluate the impacts of interrupting Firm Demand without knowing where the Load is connected to the BES system. The historical
information is not related to historical planned Load interruption, but rather the historical performance of similar Facilities.
However, If an entity does not have its own historical information available then it should use other available data to make its best
estimate of what the values will be. No change made.
New England States Committee
on Electricity (NESCOE)

Yes

NESCOE agrees with the list provided in Section II. Regarding item #7, in the interest
of explicit direction, NESCOE suggests adding at the end of the sentence the
following language: “and cost comparisons of all alternatives.”

Response: Cost considerations will be part of a rationale for selection or non-selection of an alternative. The SDT believes the
current terminology captures this concept. No change made.
Ameren

Yes

We believe that item 1b of Section II would contain critical electric infrastructure
information (CEII) and should have limited distribution. The appropriate nondisclosure agreements would need to be developed to prevent widespread
publication of the material.

Response: If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect
that information while still providing the basics of the information needed for the process to continue. No change made.
Duke Energy

Yes

Florida Municipal Power Agency

Yes

Lakeland Electric
Gainesville Regional Utilities
Southern Company

Yes

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Yes or No

Western Area Power
Administration

Yes

American Electric Power

Yes

Seminole Electric Cooperative,
Inc.

Yes

Deseret Generation &
Transmission

Yes

Platte River Power Authority

Yes

Massachusetts Attorney General

Yes

California Independent System
Operator

Yes

Public Service Company of New
Mexico

Yes

Idaho Power Company

Yes

Georgia Transmission Corp

Yes

Modesto Irrigation District

Yes

Question 3 Comment

Response: Thank you for your support.

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4.

Do you agree with the text in Section III of Attachment 1? If you do not support these changes or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The majority of the comments received here are similar to those submitted for question 1 and similar
responses have been provided.
The following clarifying changes were made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure ensure that the
applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues does not object to the
use of Firm Demand interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority authorities or
governing bodybodies responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.
Organization

Yes or No

Public Utility District No.1 of
Snohomish County

No

MEAG Power
City of Austin
Clark Public Utilities

Consideration of Comments: Project 2010-11

Question 4 Comment
1) Similar to our comment on question 2, please remove the words “as an element
of a Corrective Action Plan” from the first sentence. There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in
both the long term and short term, not as a temporary patch. Since a Corrective
Action Plan is a “list of actions and an associated timetable for implementation to
remedy a specific problem,” using this term removes the stakeholders ability to
evaluate the costs and benefits and instead requires them to treat this a problem
where the only solution is building new facilities.
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Question 4 Comment
2) For any specific use of footnote b, there could be several applicable regulatory
authorities such as small municipalities or public utility districts. The standard
should clarify whether the planner must show evidence that every authority did not
object, or whether the planner only needs to show that less that 25 MW was not
rejected by the regulatory authorities. To accomplish this clarification, we propose:
A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or
governing body” to “regulatory authorities or governing bodies.” B) Add a sentence
to bullet 2 to read “If multiple regulatory authorities or governing bodies are
responsible for retail electric service issues, only the portion of Non-Consequential
Load Loss exceeding 25 MW is subject to section III.”

Tacoma Power

No

1) Similar to our comment on question 2, please remove the words “as an element
of a Corrective Action Plan” from the first sentence. There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in
both the long term and short term, not as a temporary patch. Since a Corrective
Action Plan is a “list of actions and an associated timetable for implementation to
remedy a specific problem,” using this term removes the stakeholders ability to
evaluate the costs and benefits and instead requires them to treat this a problem
where the only solution is building new facilities.
2) For any specific use of footnote b, there could be several applicable regulatory
authorities such as small municipalities or public utility districts. The standard
should clarify whether the planner must show evidence that every authority did not
object, or whether the planner only needs to show that less that 25 MW was not
rejected by the regulatory authorities. To accomplish this clarification, we propose:
A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or
governing body” to “regulatory authorities or governing bodies.” B) Add a sentence
to bullet 2 to read “If multiple regulatory authorities or governing bodies are
responsible for retail electric service issues, only the portion of Non-Consequential
Load Loss exceeding 25 MW is subject to section III.”

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Yes or No

Question 4 Comment

Response: (1) The SDT disagrees. When alternatives and the rationale for selection or non-selection of those alternatives are
presented, cost factors can certainly be part of the rationale. In proposed TPL-001-2a, Requirement R2, Part 2.7.1, a list of possible
actions that could be included in a Corrective Action Plan is provided. This list shows several alternatives that do not require the
building of new Facilities. No change made.
(2) The SDT agrees that the plural use of the terms shown in A) above should be consistent throughout the document and has made
corresponding changes to reflect this. The SDT does not agree with the proposed change shown in B). The footnote is applicable for
a single Contingency and ownership or jurisdictional concerns do not come into play. The total value of Load affected by the single
Contingency is the correct value to determine if the situation is subject to Section III.
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure
ensure that the applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues
does not object to the use of Firm Demand interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority authorities
or governing bodybodies responsible for retail electric service issues does not object to the use of Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
MRO NSRF

No

USACE

(1) In Attachment 1 Section III, what is the definition of “applicable regulatory
authority or governing body”? Is this the state PSC or PUC? Is it the Regional
Reliability Organization (RRO)? Is it the Reliability Coordinator (RC)?
RECOMMENDATION: Depending on the answer to the above question, define
“applicable regulatory authority or governing body” more precisely. The language
could read “applicable regulatory authority or governing body responsible for retail
electric service such as the state Public Services Commission or Public Utilities
Commission”. A less vague statement allows the important parties to be included in
every instance Attachment 1 is used.
(2) In Attachment 1, if non-consequential load loss is planned at multiple bulk
delivery points to mitigate the same contingency should the total load loss count

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Yes or No

Question 4 Comment
towards the 25 MW and 75 MW thresholds or should the loads be counted
individually? EXAMPLE: There are two load serving substations (X load at substation
B and Y load at substation C) on a long 115 kV line with 230/115 kV transformation
at each end (substation A and substation D). Automatic under-voltage load shedding
is in place at substations B and C, the UVLS relays at each substation making load
trip decisions based on local voltage (i.e. independent operation). If one end of the
115 kV line trips and 115 kV voltage is below allowable levels at both substations X
and Y, then the total load tripped by UVLS will be X+Y. Does the X+Y value count
towards the 25 MW and 75 MW thresholds or are X and Y counted separately?
What if X load is dropped for one contingency and Y load is dropped for a different
contingency, is the total load counted X+Y or each load separately?
RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’ could
read “In no case can the planned Firm Demand interruption under footnote ‘b’
exceed 75 MW for any single contingency.” Similar language could be added in
Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the
two thresholds and decrease confusion.
(3) If non-consequential load loss is planned at multiple bulk delivery points in close
proximity to mitigate different contingencies should the total load loss count
towards the 25 MW and 75 MW thresholds or should the loads be compared
individually? For example, there are two load serving substations (X load at
substation B and Y load at substation C) on a networked 115 kV line with 230/115
kV transformation at both ends (substation A and substation D). Automatic undervoltage load shedding is in place at substations B and C that would trip X amount of
load if one end of the 115 kV line tripped and 115 kV voltage was below allowable
levels, and would trip Y amount of load if the other end of the 115 kV line tripped
and 115 kV voltage was below allowable levels. Does the X+Y value count towards
the 25 MW and 75 MW thresholds or are X and Y counted separately? In addition to
the aforementioned contingencies, if the 115 kV line between substations B and C
opens, both loads X and Y will trip. Now does the X+Y value count towards the 25

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Yes or No

Question 4 Comment
MW and 75 MW thresholds?
(4) In Attachment 1, if UVLS relaying is programmed at a sub to trip the load in
stages at multiple voltage setpoints, such that only a fraction of the load is tripped
for a given contingency, is the entirety of the load still counted towards the 25 MW
and 75 MW thresholds? EXAMPLE: Substation B has X load that will trip if the BES
voltage gets to 0.92 p.u. and Y that will trip if the BES voltage gets to 0.88 p.u. If only
X amount of load is required to mitigate a single contingency in the near-term TPL
assessment, is X load counted towards the 25 MW and 75 MW thresholds or is X+Y
load counted? Is there a difference if the Y load is at a different, nearby substation
with both loads having the aforementioned tripping logic? RECOMMENDATION: In
TPL-002-1c, the last sentence in Table I footnote ‘b’ could read “In no case can the
planned Firm Demand interruption under footnote ‘b’ (as demonstrated in the nearterm horizon analysis) exceed 75 MW.” Similar language could be added in
Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the
two thresholds and decrease confusion

Minnkota Power Cooperative

No

Otter Tail Power Company

1. MPC QUESTION: In Attachment 1 Section III, what is the definition of “applicable
regulatory authority or governing body”? a. Is this the state Public Service
Commission or Public Utilities Commission, the Regional Reliability Organization
(RRO), and/or the Reliability Coordinator (RC)? b. RECOMMENDATION: Depending
on the answer to the above question, define “applicable regulatory authority or
governing body” more precisely. The language could read “applicable regulatory
authority or governing body responsible for retail electric service such as the state
Public Services Commission or Public Utilities Commission”. A clearly defined
statement allows the Transmission Planner and Planning Coordinator to identify the
appropriate parties to be included in every instance Attachment 1 is used.
2. MPC QUESTION: In Attachment 1, if non-consequential load loss is planned at
multiple bulk delivery points to mitigate the same contingency should the total load
loss count towards the 25 MW and 75 MW thresholds or should the loads be

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Yes or No

Question 4 Comment
counted individually? a. EXAMPLE: There are two load serving substations (X load at
substation B and Y load at substation C) on a long 115 kV line with 230/115 kV
transformation at each end (substation A and substation D). Automatic undervoltage load shedding is in place at substations B and C, the UVLS relays at each
substation making load trip decisions based on local voltage (i.e. independent
operation). If one end of the 115 kV line trips and 115 kV voltage is below allowable
levels at both substations X and Y, then the total load tripped by UVLS will be X+Y. i.
Does the X+Y value count towards the 25 MW and 75 MW thresholds or are X and Y
counted separately? ii. What if X load is dropped for one contingency and Y load is
dropped for a different contingency, is the total load counted X+Y or each load
separately? b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I
footnote ‘b’ could read “In no case can the planned Firm Demand interruption
under footnote ‘b’ exceed 75 MW for any single contingency.” Similar language
could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW
thresholds and in TPL-001-2a as well. This clarification would explain much more
clearly what is counted towards the two thresholds and decrease confusion.
3. MPC QUESTION: In Attachment 1, if UVLS relaying is programmed at a sub to trip
the load in stages at multiple voltage setpoints, such that only a fraction of the load
is tripped for a given contingency, is the entirety of the load still counted towards
the 25 MW and 75 MW thresholds? a. EXAMPLE: Substation B has X load that will
trip if the BES voltage gets to 0.92 p.u. and Y that will trip if the BES voltage gets to
0.88 p.u. i. If only X amount of load is required to mitigate a single contingency in
the near-term TPL assessment, is X load counted towards the 25 MW and 75 MW
thresholds or is X+Y load counted? ii. Is there a difference if the Y load is at a
different, nearby substation with both loads having the aforementioned tripping
logic? b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’
could read “In no case can the planned Firm Demand interruption under footnote
‘b’ (as demonstrated in the near-term horizon analysis) exceed 75 MW at a single
substation.” Similar language could be added in Attachment 1 Section III in regards
to the 25 MW and 75 MW thresholds and in TPL-001-2a as well. This would explain

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Yes or No

Question 4 Comment
much more clearly what is counted towards the two thresholds and decrease
confusion.

Response: (1) The SDT believes that any attempt to more specifically enumerate regulatory bodies will result in the exact opposite
effect of what is stated in that inevitably there will be a one-off situation that doesn’t fit the statement. The SDT believes that the
entity will know who needs to be involved and will take the appropriate steps to make certain that the correct parties are involved.
No change made.
(2) Footnote ‘b’ only applies to single Contingencies so the SDT believes that adding the suggested words would be redundant. In the
specific example cited, if the actions taken are the result of the same single Contingency, then the total value of the Load shed would
be applicable. No change made.
(3) If the Load shed is the result of different Contingencies, the proximity doesn’t matter and the Load would be counted separately.
(4) The SDT believes that the suggested wording would be redundant. Only Load shed due to a single Contingency is applicable here.
No change made.
ACES Power Marketing Standards
Collaborators

No

(1) We disagree with the threshold of 75 MW, as mentioned above.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southern California Edison
Company

No

Consideration of Comments: Project 2010-11

As applied to SCE’s service territory, Section III of Attachment 1 appears to require
written acknowledgement and approval by the CPUC of each and every Firm
Demand interruption authorized by the CAISO’s annual transmission plan. In
California, the CPUC is notified of and invited to every CAISO meeting on
transmission planning, but the CPUC generally does not provide specific written
assurances or agreement on detailed elements of the CAISO transmission plan. SCE
believes that a general approval of the overall plan from the regulatory body should

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Question 4 Comment
be adequate.

Response: The SDT disagrees that formal approval is required for every instance of Firm Demand interruption as Section III only
applies for Load over 25 MW. Obtaining assurance from regulators that they do not object will undoubtedly occur in different ways.
Some regulators may provide written assurances or agreement but that is not required by the standard. No change made.
Bonneville Power Administration

No

For use of Non-Consequential Load Loss in Year One of the Planning Assessment,
BPA believes that assurance received from the applicable regulatory authority or
governing body responsible for retail electric service issues is adequate and
submission to the ERO for a determination of adverse impact is unnecessary. The
local utility and regulators are better positioned to determine adverse impacts on
an individual system, whereas the ERO would have to develop a process and criteria
for assessing adverse impacts.

Response: The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The
ERO is aware of the proposed responsibility and has accepted this role if the industry approves. No change made.
Tri-State Generation &
Transmission Association

No

How would section III of “Attachment 1” be applied to entities that only deliver
wholesale electric service and no retail electric service?

Response: The SDT believes that the wholesale customer will be one of the stakeholders included in the process and any use of the
footnote must go through the stakeholder process. No change made.
Modesto Irrigation District

No

Consideration of Comments: Project 2010-11

I am voting NO because there is no technical basis for use of the 75 and 25 MW
absolute threshold values, regardless of the size of the utility's load, referenced in
the proposed standard. WECC's past experience with implementation of arbitrary
magnitudes for requirements (e.g., the 5% and 7% arbitrary magnitude contingency
reserve requirements), has proved to be problematic. I would suggest investigating
a technical basis for using a relative requirement, such as percentage of the utility's
load, maybe 5% and 2.5%, respectively, and that it be based on technical
requirements similar to those found in Table 1 of the WECC Criteria TPL-001-WECC-

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Question 4 Comment
CRT-2.Thank you.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Utilizing a percentage of an entity’s Load may be
problematic – when dealing with a small entity it could be a small value but still of rather large import and if dealing with a large
entity could result in significant amounts of Load shed being planned. And, the FERC Order states that a percentage approach would
not be appropriate for the aforementioned reasons. The SDT believes that any deviation from the threshold derived from the actual
data may be viewed as a non-acceptable least common denominator approach. No change made.
Electric Reliability Council of
Texas, Inc.

No

If non-consequential load shedding is allowed for single contingency conditions, as
discussed above, it should be based on objective critieria. As such, there is no need
for the proposed stakeholder process, including the Section Ill instances requiring
regulatory review.
Furthermore, establishing approval roles in planning processes for entities other
than the relevant functional entities conflicts with the appropriate roles, and
appropriate separation of those roles, of the relevant entities (i.e. the planning
authority and the state regulatory body and NERC RE). Typically a functional entity
performs the functional activity, and others relevant to the proposed process in the
standard perform compliance and regulatory oversight of the functional
performance. This is a practical concern, and also potentially raises conflicts
between governing authorities that create the separation of roles, where, typically,
the relevant authorities establish a functional entity as the planning entity, and
NERC and its REs and state regulators (as relevant - e.g. in ERCOT) are charged with
compliance and regulatory oversight. As with the other stakeholder process
sections, that section should be eliminated.

Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted

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Question 4 Comment

draft added detail and specificity to the already approved approach. No change made.
The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. While formal
approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not require formal
approval but rather a lack of dissent. No change made.
National Association of
Regulatory Utility Commissioners

No

It appears that the 25 MW minimum value is merely a reflection of antidotal
information from a small number of data request responders and as such is not
technically justified. NARUC is not poised to offer an alternative; given that the
State/local regulator is consulted in this process, States should be appraised if any
load is anticipated to be shed under any planning criteria. Thus, no mimimum value
should be set.

Response: The data request is not anecdotal information. All of the Transmission Planners in the continental United States supplied
their data in response to the data request. The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the
planning process without a cap on the amount of Load planned to be shed. The SDT also believes that such a position is consistent
with the wording in the Order. Absent any alternative suggestion and given the participation of appropriate regulatory bodies in
both Sections I and III, the SDT believes that the current threshold is the best possible solution. No change made.
Xcel Energy

No

It does not appear that an entity has any options if the applicable regulatory
authority or governing body objects to the use of NCLL in year one. This could
potentially occur as a result of load patterns and generation issues submitted by an
LSE not necessarily having BES elements and the only solution is to implement NCLL.
In year one, it is too late to build any necessary and NCLL may be the only
alternative.

Response: While the requirement is not mandatory until Year One, the SDT believes that it would be a good practice to move
forward as soon as an entity knows it is contemplating usage of the footnote. That way, alternatives can be openly discussed before
time becomes an overriding concern. The instance described above points to the need for the stakeholder process as this process
will facilitate closer coordination with the Load-Serving Entities providing the information and the applicable regulators. No change
made.

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Yes or No

MidAmerican Energy Company

No

Question 4 Comment
Item III of Attachment I should be deleted completely. Non ERO regulatory review is
not necessary. Applicable regulatory authority or governing bodies responsible for
retail electric service issues are stakeholders which may participate in the
stakeholder process. Further, there are concerns compliance may not be possible
because item III makes non-NERC applicable regulatory authorities or governing
bodies responsible for retail electric service issues part of a NERC mandatory
compliance without consequence to the said non-NERC governing bodies. NonNERC entities are not constrained by NERC mandatory laws and penalties and aren't
compelled to perform actions to meet NERC compliance. This opens a risk to any
NERC regulated entities governed by such regulatory or governing bodies that do
not or may not feel compelled to have a process for the NERC regulatory review
specified in item III of attachment I.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today.
While formal approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not
require formal approval but rather a lack of dissent. No change made.
New England States Committee
on Electricity (NESCOE)

No

NESCOE is concerned that the 25 MW minimum value for regulatory review lacks
sufficient technical justification. NESCOE understands that the SDT used responses
to data requests to establish this 25 MW value, which is based on the average
number of MWs that entities applying footnote “b” reported using in transmission
planning. This may be a good starting point, but additional analysis is warranted.
Specifically, the analysis should consider a more direct nexus to the system, such as
substation design criteria.
Additionally, as detailed above, Attachment 1 should provide clarity regarding the
meaning of “applicable regulatory authorities.” Moreover, clarification is required
regarding the initial triggering factor for regulatory review.
Section III states that the regulatory review process is required before the footnote
can be utilized in “Year One” of the planning horizon. Does this mean that such
regulatory review only applies to year one or does it apply to year one and beyond?

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Yes or No

Question 4 Comment
If the former, NERC needs to provide a clear rationale for restricting such review
when limiting factors are already applied (i.e., voltages greater than 300 kV or a 25
MW minimum threshold value).

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Other considerations can be a point of reference or sanity
check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach and that no further
research is required. No change made.
The SDT believes that any attempt to more specifically enumerate regulatory bodies will result in the exact opposite effect of what is
stated in that inevitably there will be a one-off situation that doesn’t fit the statement. The SDT believes that the entity will know
who needs to be involved and will take the appropriate steps to make certain that the correct parties are involved. The only
mandated trigger for review is the need to have met the stipulations of the footnote and attachment prior to utilizing Load shed for
single Contingencies in a Corrective Action Plan in Year One. While the requirement is not mandatory until Year One, the SDT
believes that it would be a good practice to move forward as soon as an entity knows it is contemplating usage of the footnote. That
way, alternatives can be openly discussed before time becomes an overriding concern. No change made.
As stated, the review is only required prior to utilizing the footnote in a Corrective Action Plan in Year One. The SDT believes this
terminology is clear and understood. No change made.
Independent Electricity System
Operator

No

Consideration of Comments: Project 2010-11

No. The process presented in Section III is overly prescriptive and requires
information not necessary to the intended purpose.As state in Q1, we disagree with
prescribing a fixed MW threshold for Non-Consequential Load Loss in a continentwide standard, and propose alternate language as stated in Q1 comments.If this
section must deal with a review of the use of footnote ‘b’/’12’ to ensure that there
are no adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local support
for the use of Non-Consequential Load Loss under footnote ‘b’/’12’, only
information items 6 and 8 from section II are relevant for this assessment-the
remainder are not required for this section and should be deleted.
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Question 4 Comment
As stated in Q2 above, the use of footnote ‘b’/’12’ shouldn not be limited to the
Near-Term Planning Horizon. We propose that the words “in Year One of the
Planning Assesssment”be deleted.Items 1 and 2 complicate this section and are
unneccesary. They should be replaced by a phrase such as “for those planning
events where the use of footnote ‘b’/’12’ is referenced”.
We disagree with the need to submit to the ERO for a determination of whether
there are any adverse reliability impacts caused by the use of Non-Consequential
Load Loss. This will introduce a new type of review at the ERO that will create
uneccesary delays and burden, and is inconsistent with and not required for all of
the other performance requirements in the TPL standards. Submitting the analysis
to the adjacent Planning Coordinators and Tranmission Planners, and any functional
entity that requests it, as called for in requirement R8 of TPL001-2 should be
sufficient.

Response: Please see the response to question 1.
Please see the response to question 2.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. The SDT believes that Requirement R8 of
proposed TPL-001-2a is an important concept for sharing information and potentially resolving local differences, but it does not
necessarily provide the wider area view that the ERO could provide. No change made.
Midwest Independent
Transmission System Operator,
Inc.

No

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our
comments under Question 5.

Response: Please see response to question 5.
Southwest Power Pool Reliability
Standards Development Team

No

Consideration of Comments: Project 2010-11

Section III is superfluous if the regulatory bodies are attending the open stakeholder
process. This section should be removed due to the fact that if there is an issue or
question on these events they should be addressed in the open stakeholder
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Question 4 Comment
meeting.
Not sure why the team decided to add the ERO as an entity to check after the
regulatory body has approved the use.
We feel like if there needs to bee coordination between affected entities that they
could participate in the open stakeholder process as well. You could add that they
include possible affected entities to the invite list of the open meeting to discuss
these footnote applications under section 1.

Response: The invitees to the stakeholder process should include all applicable entities and would be expected to include applicable
regulatory bodies as shown. However, there is existing protocol for relationships between functional entities and regulatory bodies
that goes beyond the extent of Section I and that is out of the purview of the SDT. That difference as well as the difference in Load
levels between Sections I and III is what drove the SDT to produce the draft as posted. No change made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. No change made.
The invitees to the stakeholder process should include all applicable entities and would be expected to include applicable regulatory
bodies as shown. However, there is existing protocol for relationships between functional entities and regulatory bodies that goes
beyond the extent of Section I and that is out of the purview of the SDT. That difference as well as the difference in Load levels
between Sections I and III is what drove the SDT to produce the draft as posted. No change made.
Western Area Power
Administration

No

See answer to Question 1.

Platte River Power Authority

No

See answer to Question 1.

Florida Municipal Power Agency

No

See FMPA Comments regarding the 75 MW threshold of Question 1.

Lakeland Electric
Gainesville Regional Utilities

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Question 4 Comment

Response: Please see response to question 1.
NBSO

No

See our comments under Q2 and Q3, above.

Response: Please see responses to questions 2 and 3.
Massachusetts Attorney General

No

The 75 MW and 25 MW limits do not belong there. It would be best if the limits
were established by stakeholder consensus and by state rulemakings.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
National Grid

No

The current document includes the language: 2. The planned Non-Consequential
Load Loss under footnote 12 is greater than or equal to 25 MW.This gives no
concept of how long customers could expect to be out of service and hence
whether this would be an appropriate approach. Suggest using a value that is based
on energy, i.e., MWh. A value of 600MWh would represent 25 MW out for 24
hours, or could be 60 MW out for 10 hours, etc. This would seem to provide a more
valuable understanding the true impact to customers in assessing the health, safety
and welfare.
It is also expected that if Demand Resources are being used that they would be
excluded from the term “non-consequencial” load, and that the value being
discussed is only that in addition to any Demand Resources being used.

Response: The Section 1600 data request showed that entities were reporting footnote ‘b’ usage strictly in terms of MW. Therefore,
the SDT decided to stay with existing terminology in this regard. In addition, duration is one of the factors required in Section II so
the time element will be known to process participants. No change made.
Upon reviewing the comments, the SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified

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Question 4 Comment

as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Hydro One Networks Inc.

No

The process presented in Section III is overly prescriptive and duplicates information
not necessary for its intended purpose.As stated in Q1, we disagree with prescribing
a fixed MW threshold for Non-Consequential Load Loss in a continent-wide
standard, and propose alternate language in our response to Q1.If this section is
required to address a review of the use of footnote 12 to ensure that there are no
wide-spread adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local support
for the use of Non-Consequential Load Loss under footnote 12, only information
items 6 and 8 from section II are relevant for this assessment-the remainder are not
required for this section and should be deleted.
Items 1 and 2 complicate this section and are unneccesary. They should be replaced
by a phrase such as “for those planning events where the use of footnote 12 is
referenced.”
We disagree with the need to submit this information to the ERO for a
determination of whether there are any Adverse Reliability impacts caused by the
use of Non-Consequential Load Loss. This will introduce a new type of review at the
ERO that will create uneccesary delays and burden, and is inconsistent with (and not
required for) all of the other performance requirements in the TPL standards.
Submitting the analysis to the adjacent Planning Coordinators and Tranmission
Planners, and any functional entity that requests it, as called for in requirement R8
of TPL-001-2 should be sufficient.

Response: Please see the response to question 1.
Items 1 and 2 place the constraints in the process that separate the less restrictive procedure outlined in Section I from the more

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restrictive procedure in Section III. The suggested change would require the same level of review for any use of the footnote. The
SDT does not believe that this is where the industry wants to go based on comments received. No change made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. Therefore, the SDT believes that there will not be
any undue delays. The SDT believes that Requirement R8 of proposed TPL-001-2a is an important concept for sharing information
and potentially resolving local differences, but it does not necessarily provide the wider area view that the ERO could provide. No
change made.
Ameren

No

The responses to the data request indicate that 33% of the respondents that use
footnote “b” would drop 20 MW or less for single contingency events. Based on the
data, we believe that the threshold for reporting should be 20 MW instead of 25
MW.
As noted above in the response to item 1, we also believe that an upper limit of 40
MW should be established, again based on the responses to the data request.
We find this proposed stakeholder process unique because we are inviting retail
regulatory authorities to become involved in the compliance process for a handful
of utilities now, but potentially for more in the future. We are unaware of any other
standards where a state governmental agency is needed to grant permission for
utilities to utilize certain aspects of the standard. We believe that this proposed
process would potentially set a bad precedent, is not good policy for either the
regulators or the transmission planners, and does not belong in a NERC standard.

Response: The SDT believes that the threshold selected is consistent with the data supplied in the data request within reasonable
limits. No change made.
Please see response to question 1.
The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. While formal
approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not require formal
approval but rather a lack of dissent. No change made.

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Arizona Public Service Company

No

Question 4 Comment
The threshold of 25 MW in item 2 of section III is too low. It should be same as the
maximum allowed value in foot note b.
In addition, AZPS does not agree that no objection assurance by the Regional Entity
should be required. Once the process has been fully vetted by the stakeholders,
including the regulatory authority for retail service, there is absolutely no need for
Regional Entity involvement. There would be no adverse affect of nonconsequential load tripping on the BES. Hence no reason for Regional Entity
involvement is needed.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a least common denominator approach and would thus be rejected. No change
made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO has
been proposed as the best choice to provide such oversight. No change made.
Manitoba Hydro

No

The word ‘assure’ should be ‘ensure’ in the opening paragraph of III. Instances for
which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is
Required.

Response: The SDT agrees and has made the change suggested.
Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure ensure that
the applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues does not
object to the use of Firm Demand interruption under footnote ‘b’ if either:
ISO New England

No

Consideration of Comments: Project 2010-11

This provision violates both the federal and state jurisdictional split over
transmission facilities, and would violate several FERC orders directing the

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independence of RTOs in the regional system planning process. Said another way,
the determinations of a federal transmission planning entity may not be required
through an ERO standard to be subject to non-jurisdictional review and approval by
state entities. Further, the provision violates Section 215 of the Federal Power Act,
as the ERO cannot require the review of a particular transmission system plan by
state entities. The following language should therefore be deleted from Section III
of Attachment 1: “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 assure that the
applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Non-Consequential Load Loss under
footnote 12... .”
Overall, the order of Section III is also notable. During year, two through ten of the
overall planning horizon the standard allows for Non-Consequential Load Loss
without state approval. In the first year of the assessment, approval becomes
required for Non-Consequential Load Loss. In year one, even if mandating state
participation and decisional authority in a federal planning process was legally
permissible, it is too late to allow for any other alternative as transmission planning,
siting and construction of non-load loss alternatives would not be completed in the
needed period. If there were non-load loss alternatives available, the use of nonconsequential load loss would not be necessary, but it would also not be part of a
transmission plan. The Regional Entities with NERC oversight perform periodic
audits and require self-certification of the planning process. By virtue of the audit
and self-certification process, NERC has the ability to monitor the use of NonConsequential Load Loss in planning assessments.
In addition to being notable for the year one timing, Section III seems incomplete.
In the case where there is objection to Non-Consequential Load Shedding, the
process appears to end without resolution. The submission to the ERO “for a
determination of whether there are any Adverse Reliability Impacts caused by the
request to utilize footnote 12 for Non-Consequential Load Loss” conflcts with

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federal law and orders of the Federal Energy Regulatory Commission. As noted
above, the ERO is not a planning entity and does not have authority to displace the
reliability planning performed by planning entities. Transmission planning entities
are those directed by FERC to make the determinations regarding adverse reliability
impacts. If any entity wishes to challenge those determinations, it may do so before
FERC under Section 215 of the Federal Power Act. Further, this provision would
conflict with orders of the FERC regarding the independence of RTOs to conduct the
regional transmission planning process. A reliability standard may not change the
scope or meaning of federal statutes nor may it contradict or collaterally attack
orders of the Federal Energy Regulatory Commission. For these reasons, this
provision should be removed from the attachment to the proposed standard.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. The
SDT does not believe that the footnote violates any regulations concerning transmission planning. The proposed process simply
brings stakeholders including local regulators to the table in an open and transparent manner. No change made.
While the requirement is not mandatory for use in a Corrective Action Plan until Year One, the SDT believes that it would be a good
practice to move forward as soon as an entity knows it is contemplating usage of the footnote. And nothing in the document
precludes such action. Since the applicable regulator would be at the table and would therefore see potential uses of the footnote
prior to Year One, the stakeholder process provides the opportunity to get any potential timing issues out before they become a
impediment. Furthermore, the remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was
proposed. This would imply that FERC does not believe that audit and self-certification is sufficient in this matter. No change made.
The ERO is not participating in the planning process. The role of the ERO is restricted to a determination of whether the planned
utilization of footnote ‘b’ will cause an Adverse Reliability Impact to the BES. The ERO has no further role in the transmission
planning process beyond that determination. No change made.
TVA Transmission Reliability
Engineering and Controls

No

TVA believes that the requirements of 25 MW as well as any Bulk contingency over
300-kV is much too burdensome. TVA believes that only larger load drops (such as
50 MW and above) should require ERO review.

Response: The SDT believes that the threshold selected is consistent with the data supplied in the data request. Increasing the

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Question 4 Comment

threshold to 50 MW is not consistent with the data supplied and the SDT believes that such an action would be viewed as a nonacceptable least common denominator approach. No change made.
Iberdrola USA

No

Why would a retail service regulator approve a 300 kV and above performance
issue?

Response: The voltage level is not the significant issue; the significant issue is making certain that the regulator understands that the
transmission plan is to shed Load for a single Contingency so that they can understand the implications of the proposed actions and
properly evaluate other available alternatives.
LCRA Transmission Service
Corporation

No

NB Power Transmission

No

Response: Without specific comments, the SDT is unable to respond.
Texas Reliability Entity

Yes

1. TRE requests clarification whether the 25 MW limit of Non-consequential Load
Loss (Section III (2)) applies to a single contingency event for a specific Transmission
Planner’s region or to the entire Planning Coordinator area. For example, if a single
contingency requires multiple Transmisson Planners to shed load, is each
Transmission Planner allowed to drop up to 25 MW of load before requiring
regulatory review? Or did the SDT intend to require the Transmission
Planners/Planning Coordinator to submit the plan for regulatory review if the total
load shed for the single contingency equals or exceeds 25 MW?
2. TRE feels that the requirement in Section III that the Planning Coordinator or
Transmission Planner must submit information to the ERO for a determination of
whether there are “any Adverse Reliability Impacts” is overly burdensome to
industry, assuming that this refers to the new definition of “Adverse Reliability
Impact” (limited to Instability and Cascading). It is extremely unlikely that any such
impacts will result from application of this footnote, and any that might occur will

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Question 4 Comment
be identified in the stakeholder process. If the ERO determination step is retained,
then a timeline should be included for completion of the ERO determination
process.

Response: The footnote is written on a single Contingency basis so the latter instance of the comment is correct – the plan should be
submitted if the total Load shed is greater than or equal to 25 MW.
Such a determination may be considered unlikely but the SDT believes that the remand Order made it clear that oversight was
required for instances where use of footnote ‘b’ was proposed. The ERO is aware of the proposed responsibility and has accepted
this role if the industry approves. Therefore, the SDT does not believe that a timeline is required. No change made.
California Independent System
Operator

Yes

Despite a public consultation process that includes the regulator(s), the standard
then calls for notification to the regulator(s) and only moving forward once the
regulator indicates that it does not oppose the shedding of load (“once assurance
has been received that...”). This is still requiring the regulator to do something, and
could be problematic if no response is provided by the regulator. How would one
address silence on the part of the regulator?

Response: The SDT believes that Sections I and III represent two separate and distinct instances of the process. In Section I, the
regulator is just one of perhaps many interested and applicable parties. However, in Section III, where larger values of Load are
involved, there is a more formal role for regulators to play. Each local situation is unique – in some there may be formal approval
provided, in others just a lack of dissent. If the regulator is silent on the proposal, the entity can move forward with the plan. No
change made.
Lincoln Electric System

Yes

Consideration of Comments: Project 2010-11

While supportive of Section III, LES believes the language in the last paragraph could
be further enhanced with the following changes [located in brackets] to ensure a
complete and accurate record is provided to the ERO."Once [written] assurance has
been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of NonConsequential Load Loss under footnote 'b', the Planning Coordinator or
Transmission Planner must submit the [written assurance and] information outlined

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Question 4 Comment
in items II.1 through II.8 above to the ERO...”.

Response: The SDT does not believe it is appropriate to add ‘written assurance’ as the requirement only involves lack of dissent. No
change made.
Duke Energy

Yes

SERC EC Planning Standards
Subcommittee

Yes

Associated Electric Cooperative
Southern Company

Yes

American Electric Power

Yes

Seminole Electric Cooperative,
Inc.

Yes

Deseret Generation &
Transmission

Yes

American Transmission Company

Yes

Public Service Company of New
Mexico

Yes

Idaho Power Company

Yes

SCE&G

Yes

Georgia Transmission Corp

Yes

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Question 4 Comment

Response: Thank you for your support.

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5.

If you have any other comments on this Standard that you haven’t already mentioned above, please provide them here:

Summary Consideration: The comments supplied for question 5 are basically repetitive of what was stated for previous questions.
Responses are provided consistent to what was stated above.
The following changes have been made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Organization

Question 5 Comment

Independent Electricity System
Operator

(1) We’d like to reiterate our support for allowing load interruption for a singlecontingency
with sufficient review/oversight and under acceptable conditions, including no adverse impact on
the reliability of the interconnected bulk power system. The reliability aspects (BES performance
requirements) should be reviewed for acceptability by the adjacent Planning Coordinators and
Transmission Planners. However, issues pertaining to economics or externalities which may not be
directly reliability-related are always available for review and debate by the stakeholders via the
regulatory processes and subject to approval by the regulatory authority of each jurisdiction
(including those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2 approved by NERC
BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the application of
footnote ‘b’/’12’ that is allowed for the P1 events. Events in P2, P4, and P5 can involve more
elements and can be more onerous and stressful to the system than the P1 events, and if use of
footnote ‘b’/’12’ is permitted in the less stressful P1 events, it should also be permitted in P2, P4
and P5 events.
(3) We suggest that NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve it. Accordingly, we believe that the focus of
footnote ‘b’, and footnote 12 should be that interruption of load must not have an adverse impact
on the reliability of the interconnected bulk power system. A continent-wide standard should
not concern itself with the reliability of supply or supply continuity for local load, as that is the

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responsibility of the applicable regulatory authority or its agencies responsible for local
transmission and retail service over the load to be curtailed.As mentioned above, NERC Standards
and their requirements should focus on what is the anticipated outcome rather than how to
achieve it. In this regard, we believe that Attachment 1 is not necessary because it prescribes a
process which goes beyond the outcome of the standard and dictates how stakeholdering must be
carried out. The individual jurisdiction should establish the process for ensuring compliance with
the standard and decide to what extent a stakeholdering process is necessary to establish the
acceptable level of load rejection for the area in a manner consistent with local transmission
established service levels.

Hydro One Networks Inc.

(1) We’d like to reiterate our support for allowing load interruption for a single contingency with
sufficient review/oversight and under acceptable conditions, including no adverse impact on the
reliability of the bulk electric system. The reliability aspects (BES performance requirements)
should be reviewed for acceptability by the adjacent Planning Coordinators and Transmission
Planners. However, issues pertaining to economics or externalities which may not be directly
reliability-related are always available for review and debate by the stakeholders via the
regulatory processes and subject to approval by the regulatory authority of each jurisdiction
(particularly those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-2a (previous TPL-001-2 approved by the NERC
BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the application of
footnote 12 that is allowed for the P1 events. If a load is allowed to be interrupted for a single EHV
transmission line contingency (Category P1), it should be allowed to interrupt the same load if the
primary breaker fails (the event becomes category P4) and the fault is cleared by other breakers.
Similarly, if the same breaker has an internal fault or there is a fault on the same bus section
(Category P2) or there is a failure of a relay (Category P5), which results in the loss of the same
EHV transmission line, it should be allowed to interrupt the same load. Events in P2, P4, and P5
can involve more elements and can be more onerouse and stressful to the system than the P1
events, and if use of footnote 12 is permitted in the less stressful P1 events, it must also be
permitted in P2, P4 and P5 events. This issue has been raised by many entities in previous
occasions and we believe the STD has not provided a convincing response.

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(3) We suggest that NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve them. Accordingly, we believe that the focus of
foot note ‘b’, and footnote 12 should be that interruption of load must not have a widespread,
adverse impact on the reliability of the interconnected BES. A continent-wide reliability standard
should not concern itself with the reliability of supply or supply continuity for local load, as that is
the responsibility of the applicable regulatory authority or its agencies responsible for local
transmission and retail service over the load to be curtailed. If NERC and/or FERC believe that MW
threshold needs to be addressed within NERC Standard for US registered entities then the
standard must clearly state that the requirement is for US registered entities only.

Response: (1) Thank you for your support.
(2) Such discussion is out of scope for this project since TPL-001-2 has been approved by the industry through the standards
development process and by the NERC Board of Trustees. Nothing in this project affects where footnote 12 is applied within Table 1.
The only change being proposed is to the details of how to utilize footnote 12 as shown in the proposed Attachment 1. No change
made.
(3) FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well defined, did
not include quantitative and qualitative criteria for allowing curtailment of Firm Demand, and did not assure that BES reliability
would be maintained. The balloted draft added detail and specificity to the already approved approach. Canadian entities are
allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use within the confines of provincial
regulations. Nothing has changed in that regard with this proposed standard. No change made.
Manitoba Hydro

(1) Effective Date section 5: The language used in the revision that was made is fine, however,
where the language has been placed in the section is confusing. The language has been added to
the end of the sentence that starts ‘in those jurisdictions where regulatory approval is not
required’ and lumped those two concepts together. In our mind, there should be 3 separate
concepts 1) where regulatory approval required 2) where regulatory approval not required and 3)
as may otherwise be approved by applicable laws.
(2) Corresponding changes do not appear to have been made, TPL 1 and TPL 2 are not consistent
in terms of the language used in the Effective Date section or the Attachment 1 (the sections to

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which changes were made since last circulation).

Response: (1) The language used in the effective date section is provided by NERC Legal and was designed to take into account the
situations raised in the comment. No change made.
(2) The SDT wishes to point out that the language may be slightly different due to the specific circumstances regarding definitions,
etc., in the timeframe relevant to the two standards. However, the SDT believes that the language used in the two standards is
consistent. Without specific references the SDT is unable to respond further. No change made.
ACES Power Marketing
Standards Collaborators

(1) The SDT needs to consider the connection between the developing standards to maintain and
improve reliability with the costs required to meet those standards. We believe there is an
imbalance of the costs associated with meeting compliance for the current draft standard with
proposed benefit of maintaining reliability of the BPS. This standard is a good candidate for the
CEAP initiative to determine the cost benefits of reliability.
(2) The standard needs to allow more flexibility regarding the use of planned load shed to address
transmission performance issues in the planning horizon. It needs to recognize that these planned
load shedding events may only be preliminary decisions for addressing problems that are several
years away. If there is little chance that the planned shed load will ever be relied upon in the
operating time horizon, there should be much less stringent requirements. For instance, if a PC or
TP relies on planned load shed for year five of the planning horizon but year one does not utilize
the planned load shed, they have four years to develop another solution. Why should an entity
expend great effort and resources for year five when another solution will likely be developed
within that time period?
(3) What does “materially changed” mean and what degree of a change would be considered
material in the Attachment 1 stakeholder process? The SDT should clarify specific conditions in
Section II that would constitute a material change.
(4) Thank you for the opportunity to comment.

Response: (1) Cost factors are one of the elements in the list of criteria in Section II. Costs of different alternatives will be part of the
information provided and rationales for selection or non-selection of alternatives should include consideration of costs. The CEAP

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initiative is still a work in progress and will not be ready for use in the timeframe of this project. No change made.
(2) The SDT agrees that more flexibility is needed in the longer term; therefore, in the Long-Term Transmission Planning Horizon the
stakeholder process is not required, and its use is limited to the Near-Term Transmission Planning Horizon. However, the SDT
believes that it is appropriate for planners to share future information in Section II so stakeholders are aware of any potential Load
shed. No change made.
(3) The SDT believes that the planning entity has the best understanding of when a change would become material. With the large
range of design philosophies and geographic difference between the entities within NERC, it is not practical to adopt a single one size
fits all approach. In addition, since the use of footnote ‘b’ will be a part of the entity’s Corrective Action Plans, interested
stakeholders will have the opportunity to question the continued use of footnote ‘b’. No change made.
Sacramento Municipal Utility
District

1) The decision of necessary infrastructure addition versus a determination of load shed in lieu of
costly transmission should be determined at the Public Utility Commission or Local Board of
Directors not through a laod level limitation.
2) There are no impacts to the BES for load shedding actions where it is determined that it is
confined to a set boundaryand demonstrate to not lead to cascading, uncrontrolled separation or
blackout.
3) Where a concern that a stakeholder process be "gamed" to allow the unscrupulous entity to
claim notification of affected stakeholders was followed should not dictate a continent-wide
standard direction for other stakeholders.

Response: 1) FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
2) The use of Footnote ‘b’ as proposed provides assurance that there is no Adverse Reliability Impact. No change made.
3) The conditions placed on the stakeholder process will provide consistency in the application of footnote ‘b’ on a continent-wide
basis. No change made.
Tri-State G&T

1. It is not clear how transmission projects with long lead times (such as T-lines) would be handled

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by “Footnote b”. In other words, it is not clear if it is acceptable for a TP to plan for shedding Firm
Demand in the Near Term Planning Horizon without meeting the conditions shown in “Attachment
1” when a mitigating project is planned that cannot be constructed in the Near Term Planning
Horizon.
2. NERC Functional Model definitions for Planning Authorities and Transmission Planners do not
include the types of activities being proposed in “Attachment 1.” As written, this standard
mandates functions on functional entities that are outside those defined by the NERC Functional
Model.
3. In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that the end-use
customer makes available to its Load-Serving Entity via contract or agreement for curtailment.”
The process described in Attachment 1 creates an agreement between stakeholders (aka “end-use
customers”) and their transmission providers for shedding Demand. Thus, if the process described
in Attachment 1 is followed, the “Firm Demand” referenced in “Footnote b” would be reclassified
as “Interruptible Demand.” In essence, Firm Demand would not be interrupted. If this was the
intention of FERC, NERC, and the Drafting Team, the standard should just state “Interruption of
Firm Demand is not allowed.”
4. It is not clear how section III of “Attachment 1” would be applied to entities that only deliver
wholesale electric service and not retail electric service.

Response: 1. Any instance of proposed Load shed for a single Contingency situation in a Planning Assessment must meet the
conditions of footnote ‘b’. No change made.
2. The NERC Functional Model is a guideline for activities required of cited functional entities. It is periodically updated as conditions
change. While the activities mentioned in the standard may not be explicitly spelled out in the NERC Functional Model, the SDT does
not believe that they are out of scope for either a Planning Coordinator or a Transmission Planner. No change made.
3. Upon reviewing the comments, the SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be
clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the

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Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
4. The SDT believes that the wholesale customer will be one of the stakeholders included in the process and any use of the footnote
must go through the stakeholder process. No change made.
MRO NSRF
USACE
MidAmerican Energy Company

Minnkota Power Cooperative
Otter Tail Power Company

1. In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption” or “NonConsequential Load Loss” be initiated by a manual event such as operator action or does it need to
be automatic? RECOMMENDATION: In TPL-002-1c Table I footnote ‘b’ add a sentence stating
“Acceptable methods to enact Firm Demand Interruption may include manual or automatic
processes that can be initiated within a reasonable timeframe”
1. MPC QUESTION: In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption”
or “Non-Consequential Load Loss” be initiated by a manual event, such as operator action, or does
it need to be automatic, such as Under Voltage Load Shedding? a. RECOMMENDATION: In TPL002-1c Table I footnote ‘b’, add a sentence stating “Acceptable methods to enact Firm Demand
Interruption may include manual or automatic processes that can be initiated within a reasonable
timeframe”

Response: Whether an action is automatic or manual is of no concern with regard to footnote ‘b’ as long as manual actions are
executable within the time duration applicable to the Facility Ratings. No change made.
California Independent System
Operator

A concern with the new TPL-001-2 standard is what we see as being the elimination of the existing
footnote c, the footnote that qualified Category C load shedding as “may be necessary”. The
wording under the new TPL-001-2 appears that load shedding is the unqualified expectation of the
criteria for C contingencies.

Response: The SDT clarified the expectations for the former Category ‘C’ Contingencies when it developed proposed TPL-001-2. TPL001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees. Nothing in this
project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how to utilize
footnote 12 as shown in the proposed Attachment 1. Any discussions concerning the application of the footnote within the
performance table are therefore out of scope for this project. No change made.

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Iberdrola USA

A one-paragraph footnote encompassing a 2-page attachment is cumbersome for a Reliability
Standard.

Response: The SDT made every effort to make the revisions required to be as simple as possible while meeting the requirements of
the remand Order. No change made.
BC Hydro and Power Authority

BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c - System
Performance Following Loss of a Single BES Element (footnote b) and TPL-001-2a - Transmission
System Planning Performance Requirements (footnote 12). BC Hydro votes YES in support of this
ballot and wishes to provide the following two comments:1.At this time BC Hydro has concerns
about the level of stakeholder consultation that might be required as a result of the
implementation of this standard and will bring this concern to the attention of our regulator if
necessary.
2.At this time BC Hydro has concerns about the instances for which regulatory review of nonconsequential load loss under footnote 12 is required and will discuss those with our regulator if
necessary.

Response: 1. and 2. The SDT understands your situation and comment and appreciates your overall support.
Hydro Québec TransÉnergie

Even if the SDT said it is not in its scope, the following difficulty with the application of note 12
needs to be addressed by NERC. There are no limit on non-consequential load loss for Single
Contingency P2-2. and P2-3. (HV only), multiple Contingencies P4 and P5 (HV only), and P6 and P7.
The note 12 allows limited non-consequential load loss for single contingency P1, Multiple
Contingency P3. Non-consequential load loss is not allowed for P2-2 and P2-3. (EHV), and P4 and
P5 (EHV). Considering the EHV Facilities, it is not reasonable to accept some non-consequential
load loss for single contingency P1 and P2-3, and then deny it for Multiple Contingency categories
P4 and P5 which are statistically less frequent than the former. Also, the Multiple Contingency P7
(for which there is no limit on non-consequential load loss) is more frequent than P2-3, P4 and P5.
This technical irregularity must be reviewed and addressed.

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Northeast Power Coordinating
Council

There are no limits on non-consequential load loss for Single Contingency P2-2 and P2-3 (HV only),
multiple Contingencies P4 and P5 (HV only), and P6 and P7. Footnote 12 allows limited nonconsequential load loss for single contingency P1, Multiple Contingency P3. Non-consequential
load loss is not allowed for P2-2 and P2-3 (EHV), and P4 and P5 (EHV). Considering the EHV
Facilities, it is not reasonable to accept some non-consequential load loss for single contingency
P1 and P2-3, and then deny it for Multiple Contingency categories P4 and P5 which are statistically
less frequent than the former. Also, the Multiple Contingency P7 (for which there is no limit on
non-consequential load loss) is more frequent than P2-3, P4 and P5. This technical irregularity
must be reviewed and addressed.

Response: TPL-001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees.
Nothing in this project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how
to utilize footnote 12 as shown in the proposed Attachment 1. No change made.
Southern California Edison
Company

Footnote “b”/Footnote 12 as currently written does not provide for an exemption to allow for the
use of Firm Demand interruption as a short-term solution to transmission problems. Many entities
would benefit from being allowed to use Footnote “b”/Footnote 12 as a temporary solution in
response to construction delays until facilities to mitigate an N-1 contingency identified in a
Planning Assessment can be installed. Under the current proposal, the stakeholder process will
provide very little value in attempting to resolve such a problem. In fact, the current Footnote
“b”/Footnote 12 could result in a stakeholder process that may actually slow the implementation
of mitigation measures for the system.

Response: The SDT does not agree that the footnote does not provide for the use of Firm Demand interruption as a short-term
solution to transmission problems. That has always been the point of the footnote and nothing in this project has changed that
intent. The only changes are to the method in which the footnote is invoked. No change made.
ISO New England

In summary, the main footnote is unobjectionable, but this standard as proposed has misplaced
jurisdictional authority under Section 215 of the Federal Power Act for both states and the ERO
through several of the process points and conditions set out in the attachment to the stardard.
The removal of references is required for the standard to comport with the law. These revisions to

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the standard can be made, which would then allow the draft standard to comply with FERC’s
further guidance and the other legal limitations described above.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. The
SDT does not believe that the footnote violates any regulations concerning transmission planning. The proposed process simply
brings stakeholders including local regulators to the table in an open and transparent manner while setting criteria for when footnote
‘b’ can potentially be utilized. The ERO is not participating in the planning process. The role of the ERO is restricted to a
determination of whether the planned utilization of footnote ‘b’ will cause an Adverse Reliability Impact to the BES. The ERO has no
further role in the transmission planning process beyond that determination. No change made.
Ameren

It might be helpful to probe further with the respondents who have no planned upgrades
identified to address the dropping of non-consequential load to see what relevant system
upgrades might entail, and the estimated costs associated with such upgrades, to address such
situations.

Response: The SDT used the Section 1600 data request process to the best of its ability within the limited timeframe afforded to this
project. No change made.
LCRA Transmission Service
Corporation

LCRA TSC disagrees with the October 2012 revision of TPL Table 1 Steady State & Stability
Performance Footnotes (TPL-002-1c, footnote ‘b’ and TPL-001-2a footnote 12). The proposed
stakeholder process required to be conducted during each Planning Assessment is overly
burdensome. Further, it is not clear from the proposed process that a key concern expressed by
the Commission with respect to use of Firm Demand load shedding is addressed - Notice to Firm
Demand Customers.
In addition, the proposed stakeholder process introduces several questions that need to be further
clarified. For example:
1) Who defines the processes and procedures to be used?
2) Who is/are the decision maker(s)?
3) Who determines if the processes and procedures were followed?

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4) Who carries out the administrative tasks (such as notice, securing meeting space,....)?
5) Who can participate? Does someone need to demonstrate a material interest in order to
participate?
6) What are the means of participation (accepted forms of communication, timelines...)?
7) What are the criteria for decision-making?
8) What is the process for dispute resolution?
How would does an Attachment become part of a NERC Standard? Should Attachment 1 be a
requirement?
In addition, support is needed for the bright-line 25 MW level.
Lastly, the statement, “Before a Firm Demand interruption under footnote ‘b’ is allowed to be
utilized as an element of a Corrective Action Plan in Year One of the Planning Assessment,” implies
that Firm Demand interruption may be used for years two through five of the Planning Assessment
without the stakeholder process.

Response: Stakeholders representing the interests of Firm Demand customers would certainly be among the parties involved in
Section I of the stakeholder process. No change made.
1) through 8) There is not a one-size-fits-all response to these questions for a continent-wide standard. The SDT provided the key
components of an open and transparent stakeholder process while allowing variations that may be required due to differing structures
and frameworks across the continent. Therefore, the answers to these questions may be different for each individual stakeholder
process.
Attachments have been used in the past in other standards and are an accepted part of a standard.
The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’
by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount of
Load that could be planned to be shed under footnote ‘b’. The 25 MW threshold was directly derived from this data. The SDT believes
that any deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator
approach. No change made.

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The SDT disagrees with the statement made by the commenter. Firm Demand interruption must go through the process for any year
in the Near-Term Transmission Planning Horizon as is clearly stated in the main body of the footnote. No change made.
TVA Transmission Reliability
Engineering and Controls

Please see responses to question #2,3, and 4. TVA believes that only load drops of higher
magnitudes go thru the Stakeholder and regulatory review.

Response: Please see responses to questions 2, 3, and 4.
Public Utility District No.1 of
Snohomish County
MEAG Power
City of Austin
Clark Public Utilities

Public Utility District No.1 of Snohomish County generally disagrees with the October 2012
revision of TPL Table 1 Steady State & Stability Performance Footnotes (Planning Events and
Extreme Events). “Footnote b) An objective of the planning process is to minimize the likelihood
and magnitude of interruption of firm transfers or Firm Demand following Contingency events.
Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm
Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a
result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. In
limited circumstances, Firm Demand may be interrupted throughout the planning horizon to
ensure that BES performance requirements are met. However, when interruption of Firm Demand
is utilized within the Near-Term Transmission Planning Horizon to address BES performance
requirements, such interruption is limited to circumstances where the use of Firm Demand
interruption meets the conditions shown in Attachment 1. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW.””Footnote 12. An objective of the
planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency 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 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.”

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The proposed revisions require that a Transmission Planner or Planning Coordinator provide
assurance that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the interruptions of firm demand under TPL-002 footnote ‘b’ or
TPL-001 footnote ‘12’ if the voltage level of the contingency is greater than 300 kV with certain
sub-conditions or if the planned interruption of firm demand under these footnotes is greater than
25 MVA. In addition, under no case can planned Non-Consequential Load Loss exceed 75 MW.The
magnitude and duration of load loss is a Level of Service (“LOS”) or Customer Service issue that is
the jurisdiction of Public Utility Commissions and Local Electric Utility and Municipality boards.
The boards and commissions represent their customers which often have diverse service and rate
expectations that often are a result of local industry requirements, geography, urban/rural
characteristics, and other factors of the particular service territory. Boards and commissions hold
public meetings seeking input on various utility matters that often address services and rates. The
rate impacts for customers are important; often more important than the service levels depending
on the particular customer or customer class. Local boards and commissions are very close to
these issues and weigh the input provided through public testimony to best represent their
customer needs over the region they represent and have jurisdiction under state and local codes
to address.The 75 MW Non-Consequential Load Loss threshold and the required NERC process do
not resolve or address a reliability issue. The TPL footnotes address service requirements and
should not be part of a NERC Reliability Standard any more than mandating specific System
Average Interruption Frequency Index ("SAIFI") and System Average Interruption Duration Index
("SAIDI"). The Non-Consequential Load Loss requirement is an economic driven threshold that is
not consistent throughout North America due to diverse customer needs and expectations. For
instance, in some areas it may make economic sense and receive local approval to fund a $100
million system reinforcement to mitigate 1 in 20 year (5 percent chance of occurring) 76 MW NonConsequential Load Loss exposure. However there are many communities that could not justify or
support multi-million facilities to mitigate a 1 in 20 year event that may cause the NonConsequential Load Loss of 76 MW of load. Public Utility District No.1 of Snohomish County
supports removing the Non-Consequential Load Loss thresholds from the TPL Reliability Standards
and allow the local boards and commissions to continue to address Customer Service Level issues
as they are closest to the customers’ needs and have jurisdiction over this issue.

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Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted
draft added detail and specificity to the already approved approach. The proposed standards include the local regulatory bodies at
every step in the process. This will allow those bodies to have input at every step. The SDT believes that the proposed changes to
the standards are in alignment with the charge that was given to it. No change made.
Xcel Energy

Setting limits on the amount of NCLL only sets the stage for failure in the compliance of NERC
standards and fails to take note of what is really the issue; the planning of a transmission system
that is both reliable and economically viable for all stakeholders and customers. It should be
emphasized that the use NCLL in a “planning process” is only assuming the conditions set in the
study will exist and in no way reflects the conditions seen during the day to day operation of the
transmission system.
Xcel Energy is concerned about the previous ability on loss of load in anticipation of the next
outage (previously C3 now P6). For TPL-003, loss of load in anticipation of the next system outage
was covered under footnote B. Footnote 9 now states, “...the re-dispatch does not result in any
Non-Consequential Load Loss. “ This is a large increase in requirements of the transmission
system to operate. As written, it appears that footnote 12 is NOT applicable to P6 contingencies.
Please clarify is this is the intent.

Response: The SDT does not believe that it needs to add language emphasizing that there is a difference between planning and
operations when these standards are clearly planning standards. No change made.
The SDT disagrees that there was a previous ability to shed Load in anticipation of the next Contingency. Footnote ‘b’ only allowed
curtailment of firm transfers in preparation for the next Contingency. In addition, footnote 12 is not applicable for P6 planning
events since Non-Consequential Load loss is allowed. No change made.
Arizona Public Service Company

The following comment relates to Table 1. It is not clear why footnote 12 applies only to P2-1. The
events P2-2, P2-3, P4, P5 are much less probable and the footnote 12 should be applicable to all
these events. Why is that loss of non-consequential load is allowed for line tripping without fault
but not for a bus fault which is much less likely and could result into same line trip. Similar

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arguments apply to other scenarios listed above.

Response: TPL-001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees.
Nothing in this project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how
to utilize footnote 12 as shown in the proposed Attachment 1. Any discussions concerning the application of the footnote within the
performance table are therefore out of scope for this project. No change made.
Electric Reliability Council of
Texas, Inc.

The SDT is not required to utilize the stakeholder approach by Order 762 or any other relevant
FERC orders. FERC merely provided guidance as to how the rejected proposal could be improved.
However, if the SDT elects to pursue an exception process, such exceptions should be based on
objective criteria, and the process should be external to the NERC Reliability Standards (e.g. in the
Rules of Procedure).In Order 693, FERC directed NERC to clarify footnote (b) to prohibit shedding
firm load except for consequential load loss (Order 693 at PP 1773, 1794 and 1797}. In a related
compliance order, FERC reaffirmed its position. (130 FERC 61,200 (March 18, 2010) at PP 8-10
(Compliance Order)) In a subsequent order, FERC clarified that its Order 693 directive did not
preclude consideration of specific comments related to planning the system based on load
shedding at the “fringes" of a system. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification
Order)) FERC held that regional variances for case-specific circumstances or a case-specific
exception process to plan for the loss of firm service “at the fringes of various systems" would be
acceptable. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification Order)) However, FERC also
stated that it viewed the basis for such exceptions as economic, not reliability, with the
justification being that it was not economic to invest in the bulk electric system to serve all nonconsequential load customers under some single contingency conditions. (Order 693 at P 1792)
FERC made clear that any such regional differences or case specific exception processes cannot
reflect the lowest common denominator, and, they must be technically justified, and such
justification must be strong. (Clarification Order at P 21, See also Order 693 at P 1794) This is
consistent with FERC's position that this is a matter of "fundamental issue of transmission service".
(Order 693 at P 1793) In recognizing that meeting firm demand under single contingency
conditions is fundamental to transmission service, FERC noted that NERC's definition of firm
transmission service is the "highest quality (priority) service offered to customers ... that
anticipates no planned interruption." (Order 693 at P 1793)Against this background, NERC filed

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revisions to footnote b that allowed transmission plans to shed non-consequential load under
single contingency conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, {139 FERC 11 61,060 (April 19, 2012)) FERC rejected
the approach proposed by NERC and provided guidance on acceptable approaches to footnote b.
However, FERC did not endorse or mandate any particular approach. Rather, it merely urged
"NERC to develop in a timely manner an appropriate modification that is responsive to the
Commission's directives in Order No. 693 and our concerns set forth in this Final Rule." (Order 762
at P21) FERC stated that in order for any such proposal to have merit, it must be technically
justified and must not reflect the lowest common denominator.As discussed, the proposed
stakeholder approach is not appropriate for NERC Reliability Standards. The SDT should abandon
that approach and consider simple revisions to footnote b that reference a case by case exception
process based on objective criteria that is external to the NERC Reliability Standards (e.g. Rules of
Procedure). Alternatively, it should develop revisions to the continent-wide standards that clarify
that non-consequential load shedding is not generally permitted for single contingency conditions,
but, consistent with FERC's orders, exceptions could be established pursuant to regional rules
based on the need/appropriateness in a particular region.Consistent with the above discussion, if
the SDT elects to pursue revisions that accommodate shedding non-consequential load in
transmission planning for single contingency conditions, it should abandon the stakeholder
process approach. The establishment of exceptions is better suited for regional rules or pursuant
to a process outside of the reliability standards - e.g. via the Rules of Procedure, because such a
process is not suited for a continent-wide reliability standard. Regardless of whether the issue is
addressed via an external process, or left to regional variances, this issue needs to be addressed in
a relatively timely manner because the uncertainty is affecting planning processes.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. The SDT has set up
criteria for consideration in the potential usage of footnote ‘b’ for planning purposes in Attachment 1, Section II, Bullets 1 through 8.
The criteria described are objective. The process described does not tell a entity how to go about its business but only describes
what must be done to allow for the usage of footnote ‘b’ in the planning process. The SDT believes that the referenced exception
process is what is being proposed. The proposed process sets up an open and transparent process for allowing such Load shed in
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specific conditions and with specific limitations. Any future revisions to footnote 12 will be accomplished through the approved
standards development process and any discussion on changing threshold values would be part of that process. No change made.
Midwest Independent
Transmission System Operator,
Inc.

We do not support using a stakeholder process to determine if Non-conseqeuntial Load Loss is
appropriate following a single contingency event as a means to satisfy the standard. Stakeholder
processes will nearly always result in disagreements. The parties that may be responsible for
payment of upgrade costs will not necessarily line up with the parties adversely impacted by the
alternative load loss. If the stakeholder process includes all stakeholders, there may be many
more stakeholders impacted by upgrade costs based on broader benefits and/or cost sharing than
stakeholders impacted by the alternative load loss. This will result in the majority decision of a
stakeholder body to most often be one that supports load shed (until it is their turn to be the load
that is shed). On the other hand, if the stakeholder process is limited to only the stakeholders
directly impacted by the proposed load shed, to the extent those stakeholders pay only a small
part of the upgrade costs, they will always select a potentially costly upgrade to avoid load shed.
The point is, we do not believe that it possible to have a fair and impartial stakeholder process to
correctly determine if and when load shed is acceptable to assist in satisfying a single contingency
standard. Since the general intents of the existing TPL-002-1 standard and proposed TPL-001-2
standard are not to rely on any shedding of non-consequenital load to meet a single contingency
event, in the event that footnote b of TPL 002-1 or footnote 12 of TPL 001-2 is not eliminated, we
believe that it should be narrowly focused only on those situations for which the original footnote
was developed: interruption of service to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, where the overall
reliability of the interconnected transmission system is not impacted. We propose that footnote b
and footnote 12 be modified as follows to ensure it is not misapplied:”An objective of the planning
process is to avoid Non-Consequential Load Loss following Contingency events. In limited
circumstances, Non-Consequential Load Loss may be needed within the planning horizon to
ensure that BES performance requirements are satisfied. However, Non-consequential Load Loss
cannot be used to avoid cascading outages or to maintain system stability. Non-consequential
Load Loss also cannot be used to avoid a thermal loading or voltage limit violation on an EHV
facility. When Non-Consequential Load Loss is utilized within the planning horizon to address BES
performance requirements, such interruption cannot exceed 75 MW and is limited to the

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following circumstances: o Non-consequential Load Loss is allowed for load served by a radial
transmission line to avoid voltage limit violations on the radial transmission line following a single
contingency event anywhere on the system.. o Non-consequential load shed is allowed for load
within a local area served by not more than two transmission lines and/or transformers to avoid a
thermal loading issue or voltage issue in the local area, including the transmission lines and/or
transformers supplying the area, for a loss of one of the transmission lines or transformers
supplying the area, so long as there are no thermal loading or voltage violations outside the local
area.”We believe the language above maintains acceptable reliability on the bulk electric system
by limiting load shed and violations that require load shed to radial areas or areas that would be
served radially following the single contingency. We therefore highly recommend that
Attachment I be eliminated entirely and that the footnotes either be eliminated or replaced with
the modified version above.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
SCE&G

While the current revisions improve the processes described, we have concerns regarding the
revisions to TPL002-1 b. SCE&G has significant concern with the proposed revision to TPL Table 1,
Footnote B. The current Footnote B states “Planned or controlled interruption of electric supply
to radial customers or some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the overall
reliability of the interconnected transmission systems” is important to the TPL standards to ensure
that ERO standards do not dictate the level of service to specific customers. Service to specific
customers and load pockets is jurisdictional to State Commissions. ERO standards should not
compromise this jurisdiction. SCE&G believes that any proposed revisions to Footnote B must
maintain the concept that planned or controlled interruption of electric supply to customers,
whether they are radial or network, is allowed as long as it does not impact the overall reliability
of the interconnected transmission systems. The proposed revision eliminates this concept

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Response: The SDT believes that the suggested wording is redundant as the quoted statement is the basis for standards activities.
No change made.
END OF REPORT

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Consideration of Comments
Project 2010-11 Revision of TPL-002 footnote ‘b’

The Project 2010-11 TPL Table 1 Order Drafting Team thanks all commenters who submitted comments
on the proposed standards, TPL-002. The standard was posted for a 30-day public comment period
from December 12, 2012 through January 11, 2013. Stakeholders were asked to provide feedback on
the standards and associated documents through a special electronic comment form. There were 49
sets of comments, including comments from approximately 132 different people from approximately
48 companies representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Summary Consideration:
The SDT made one change to the proposed standards to address industry comments. This change was
made in the main body of the footnote to address a specific jurisdictional concern for non-US entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW for US registered entities. The amount
of planned Non-Consequential 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.
In order to avoid confusion, a duplicative statement on the applicability of the 75 MW constraint was
deleted from Section III.
The SDT also corrected the grammar in Section III, changing ‘does’ to ‘do’ in the applicable sentences,
as follows:
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail
electric service issues does not object …”
In addition, in the course of researching industry comments, a typo was discovered and corrected as
follows:
TPL-002-1c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as
Firm Demand t: (1) …”
No other changes were made.
While the revision for non-US registered entities qualifies as a significant change to the standards, the
Standards Committee has decided that since the indicated change was simply for a jurisdictional issue,
and did not change the technical content or intent of the standard, that this project can be moved
forward to the recirculation ballot stage.

Unresolved minority issues:
Some respondents continue to raise jurisdictional concerns with the proposed standards. The general
line of thought in those comments is that NERC is imposing itself into the local planning process in
violation of existing statutes. The proposed solution allows for input and participation at every step of
the process by local jurisdictional authorities. In Order 693, FERC clearly stated that it has jurisdiction
over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO
to write standards and requirements to address all aspects of BES operations and reliability in support
of these goals. The proposed footnote ‘b’ solution acknowledges these facts and the SDT believes it is
an appropriate response to FERC directives on this matter.
Many commenters questioned the use of a stakeholder process at all. Those commenters expressed
the opinion that the FERC Order did not mandate the use of the stakeholder process. The SDT used the
Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard;
not because it contained a stakeholder process, but because the process was not well defined, did not
include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure
that BES reliability would be maintained. The balloted draft added detail and specificity to the already
approved approach, in order to address these concerns.
A few commenters indicated disagreement with the 75 MW limit the proposed standards place on the
amount of Non-Consequential Load that can be planned to be shed for a single contingency, with some
commenters indicating that the limit should be higher than the proposed limit while others indicated
that planning to shed load was inconsistent with planning for a reliable bulk power system.
Finally, some commenters continue to question facets of the proposed TPL-001-2a standard previously
approved by the industry and the NERC Board of Trustees. These commenters are questioning the
application (or non-application) of footnote 12 for various planning events. . The SAR for this project
took the approved TPL-001-2 as the starting point for the specific discussion of footnote ‘b’/12 and
does not allow for review of previously approved applications of the footnote, which were developed
and reached ballot pool consensus and Board approval in a previous effort.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

2

Index to Questions, Comments, and Responses
1.

Do you agree with changes made to the body of the footnote? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comment ....................................................................11

2.

Do you agree with the changes contained in Section II of Attachment 1? If you do not support
these changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments ..............................................28

3.

Do you agree with changes contained in Section III of Attachment 1? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ..................................................................36

4.

If you have any other comments on this Standard that you haven’t already mentioned above, and
that are not simply reiterating previous comments that the SDT has already responded to, please
provide them here:...........................................................................................................................45

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Jim Kelley

Additional Member

Additional Organization

SERC EC Planning Standards Subcommittee

Ameren Services Company

SERC

1

2. Charles Long

Entergy

SERC

1

3. Edin Habibovic

Entergy

SERC

1

4. James Manning

NC Electric Membership Corporation SERC

1

5. Philip Kleckley

SC Electric & Gas

SERC

1

6. Shih-Min Hsu

Southern Company Service

SERC

1

7. Darrin Church

TVA

SERC

1

8. Bob Jones

Southern Company Service

SERC

1

9. Pat Huntley

SERC Reliability Corporation

SERC

10

Group

Guy Zito

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. John Sullivan

2.

X

2

Northeast Power Coordinating Council

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization

Alan Adamson

New York State Reliability Council, LLC NPCC 10

2.

Carmen Agavriloai

Independent Electricity System Operator NPCC 2

3.

Greg Campoli

New York Independent System Operator NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Wayne Sipperly

New York Power Authority

NPCC 5

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8.

Kathleen Goodman

ISO - New England

NPCC 2

9.

Donald Weaver

New Brunswick System Operator

NPCC 2

10. David Kiguel

Hydro One Networks Inc.

NPCC 1

11. Christina Loncz

PSEG Power LLC

NPCC 5

12. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

13. Bruce Metruck

New York Power Authority

NPCC 6

14. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Brian Robinson

Utility Services

NPCC 8

Group

Southwest Power Pool Reliability Standards
Development Group

Jonathan Hayes

3

4

5

6

7

Region Segment Selection

1.

3.

2

X

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Jonathan Hayes

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

3. Tiffany Lake

Westar Energy

SPP

1, 3, 5, 6

4. Don Taylor

Westar Energy

SPP

1, 3, 5, 6

5. Stephen McGie

City of Coffeyville

SPP

NA

6. Valerie Pinamonti

American Electric Power SPP

4.

Group

Jamison Dye

1, 3, 5

Bonneville Power Administration

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5.

Group

Terry L. Blackwell

Santee Cooper

2

3

X

X

X

X

4

5

6

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Vicky Budreau

Santee Cooper

SERC

1

2. Jim Peterson

Santee Cooper

SERC

1

3. Chris Jimenez

Santee Cooper

SERC

1

4. Chris Wagner

Santee Cooper

5. Cindy Corson

Santee Cooper

6. Mike Coker

Santee Cooper

SERC

1

7. Rene' Free

Santee Cooper

SERC

1

8. Tom Abrams

Santee Cooper

SERC

1

9. Rick Thornton

Santee Cooper

SERC

1

6.

Group

1
1

paul haase

seattle city light

X

Additional Member Additional Organization Region Segment Selection
1. pawel krupa

seattle city light

WECC 1

2. dana wheelock

seattle city light

WECC 3

3. hao li

seattle city light

WECC 4

4. mike haynes

seattle city light

WECC 5

5. dennis sismaet

seattle city light

WECC 6

7.

Group

Ben Engelby

Additional
Member

X

ACES Standards Collaborators
Additional Organization

Region

Segment
Selection

1. John Shaver

Arizona Electric Power Cooperative Inc./Southwest Transmission
Cooperative Inc.

WECC 1, 4, 5

2. Shari Heino

Brazos Electric Power Cooperative, Inc.

ERCOT 1, 5

3. Amber Anderson

East Kentucky Power Cooperative

SERC

1, 3, 5

4. Megan Wagner

Sunflower Electric Power Corporation

SPP

1

5. Bill Hutchison

Southern Illinois Power Cooperative

SERC

1

6. Scott Brame

North Carolina Electric Membership Corporation

RFC

1, 3, 4, 5

8.

Group

WILL SMITH

MRO NSRF

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

OPPD

MRO

1, 3, 5, 6

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2.

TOM BREENE

WPS

MRO

3, 4, 5, 6

3.

JODI JENSON

WAPA

MRO

1, 6

4.

KEN GOLDSMITH

ALTW

MRO

4

5.

DAVE RUDPOLPH BEPC

MRO

1, 3, 5, 6

6.

ERIC RUSKAMP

MRO

1, 3, 5, 6

7.

JOE DEPOORTER MGE

MRO

3, 4, 5, 6

8.

SCOTT NICKELS

RPU

MRO

4

9.

TERRY HARBOUR MEC

MRO

1, 3, 5, 6

LES

10. MARIE KNOX

MISO

MRO

2

11. LEE KITTELSON

OTP

MRO

1, 3, 5

12. SCOTT BOS

MPW

MRO

1, 3, 5, 6

13. TONY EDDLEMAN NPPD

MRO

1, 3, 5

14. MIKE BRYTOWSKI GRE

MRO

1, 3, 5, 6

15. DAN INMAN

MPC

MRO

1, 3, 5, 6

9.

Greg Rowland

Group

Duke Energy

X

2

3

X

4

5

X

6

7

X

Additional Member Additional Organization Region Segment Selection
1. Doug Hils

Duke Energy

RFC

1

2. Lee Schuster

Duke Energy

FRCC

3

3. Dale Goodwine

Duke Energy

SERC

5

4. Greg Cecil

Duke Energy

RFC

6

10.

Group

Sasa Maljukan

Additional Member
1. David Kiguel

Hydro One Networks Inc.

X

Additional Organization Region Segment Selection
Hydro One Networks Inc. NPCC 1

2. Hamid Hamadanizadeh Hydro One Networks Inc. NPCC 1

11.

Group

John Allen

Additional Member

Additional Organization

Iberdrola USA
Region Segment Selection

1. Joseph Turano

Central Maine Power

2. Raymond Kinney

New York State Electric & Gas NPCC 1

3. David Conroy

Central Maine Power

12.

Group

Michael Jones

Additional Member

X

NPCC 1
NPCC 1

National Grid

Additional Organization

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X

X

Region Segment Selection

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Michael Schiavone

13.
14.
15.

Individual

Chris Pink

Individual

Tim Ponseti, VP

Individual

Diane Barney

Tri-State G&T
TVA Transmission Reliability Engineering
and Controls

X

17.

Individual

Shih-Min Hsu

Southern Company

18.

Individual

Frederick R Plett

Massachusetts Attorney General

19.

Individual

Thad Ness

American Electric Power

X

20.

Individual

Oliver Burke

Entergy Services, Inc. (Transmission)

X

Individual
22. Individual

Chris de Graffenried
David Jendras

Consolidated Edison Co. of NY, Inc.
Ameren

23.

Individual

Nazra Gladu

Manitoba Hydro

24.

Individual

David Wang

SDG&E

25.

Individual

Bob Easton

Individual
Individual

Kenn Backholm
Steve Alexxanderson
P.E.

WAPA-RMR
Public Utility District No.1 of Snohomish
County

28.

Individual

Milorad Papic

Idaho Power Company

29.

Individual

Russ Schneider

Flathead Electric Cooperative, Inc.

30.

Individual

Cheryl Moseley

Electric Reliability Council of Texas, Inc.

31.

Individual

Jim Cyrulewski

JDRJC Associates LLC

32.

Individual

Kathleen Goodman

ISO New England Inc

33.

Individual

John Collins

Platte River Power Authority

X

34.

Individual

Keith Morisette

Tacoma Power

X

27.

5

6

7

8

9

X

X
X
X

Lloyd A. Linke

26.

4

X

Individual

21.

3

Niagara Mohawk (A National Grid Company) NPCC 3

NARUC
Western Area Power Administration Transmission Owner

16.

2

X
X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X

Central Lincoln

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X
X
X
X
X

X

X

X

8

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

35.

Donald Weaver

Individual

Michiko Sell

New Brunswick System Operator
Public Utility District No. 2 of Grant County,
WA

Individual
38. Individual

Michael Moltane
Mark Westendorf

ITC
MISO

X

39.

Individual

Michael R. Lombardi

Northeast Utilities

40.

Individual

Patricia Robertson

BC Hydro

X
X

41.

Individual

Teresa Czyz

Georgia Transmission Corp.

X

42.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

43.

Individual

Clay Young

SCE&G

X

44.

Individual

Michael Falvo

Independent Electricity System Operator

45.

Individual

Brett Holland

Kansas City Power & Light

X

46.

Individual

Oncor Electric Delivery Company LLC

X

Individual

Darryl Curtis
Vijayraghavan
bangalore

48.

Individual

Alice Ireland

Xcel Energy

X

49.

Individual

Tony Kroskey

Brazos Electric Power Cooperative, Inc.

X

37.

47.

3

4

5

6

7

X

Individual

36.

2

X

X

X

X

X

X
X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

X
Pacific gas and Electric Comapny

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

9

8

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: The SDT thanks you for following the instructions and lessening the SDT workload. Your support for
comments submitted by another entity will be noted accordingly.
Organization

Supporting Comments of “Entity Name”

Flathead Electric Cooperative, Inc.

We support the comments submitted by Central Lincoln

JDRJC Associates LLC

Midwest ISO

Kansas City Power & Light

SPP

Brazos Electric Power Cooperative, Inc.

ACES Power Marketing

ITC

MISO

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

10

1.

Do you agree with changes made to the body of the footnote? If you do not support these changes or you agree in general but
feel that alternative language would be more appropriate, please provide specific suggestions in your comment

Summary Consideration: In general, the SDT has responded to the individual comments and there are no technical changes proposed
to the standards as a result of comments. However, the SDT has responded to a request from Canadian entities to make a change to the
main body of the footnotes to address specific jurisdictional concerns for non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under
footnote ‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
While the revision for non-US registered entities qualifies as a significant change to the standards, the Standards Committee has decided
that since the indicated change was simply for a jurisdictional issue, and did not change the technical content or intent of the standard,
that this project can be moved forward to the recirculation ballot stage.
Organization

Yes or No

Northeast Power Coordinating Council

No

Question 1 Comment
Dropping load generally should not be endorsed, but it is recognized that
there are special situations where it cannot be avoided. If a regulator
responsible for load is comfortable with greater than 75MW being
dropped in a rare situation, there should not be a requirement to build
out of the situation.
Provided there is no widespread, adverse effect on the reliability of the
interconnected BES, the effect of a interruption on customers is under
the purview of the applicable regulatory authority that is responsible for
local transmission and retail service over the load to be curtailed. NERC
must acknowledge that jurisdictional authorities can decide on the
parameters for planning events that do not have an impact on the
reliability of interconnected BES .
There are no limits on non-consequential load loss for Single Contingency

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

11

Organization

Yes or No

Question 1 Comment
P2-2 and P2-3 (HV only), multiple Contingencies P4 and P5 (HV only), and
P6 and P7. Footnote 12 allows limited non-consequential load loss for
single contingency P1, Multiple Contingency P3. Non-consequential load
loss is not allowed for P2-2 and P2-3 (EHV), and P4 and P5 (EHV).
Considering the extensive EHV Facilities in the Canadian regions of NPCC,
it is not reasonable to accept some non-consequential load loss for
single contingency P1 and P2-3, and then deny it for Multiple
Contingency categories P4 and P5 which are statistically less frequent
than the former. Also, the Multiple Contingency P7 (for which there is no
limit on non-consequential load loss) is more frequent than P2-3, P4 and
P5. This technical irregularity must be reviewed and addressed. This
comment was submitted for the last posting.

Response: The SDT has previously pointed out that building is not the sole source of remedy for the situation. Examples of other
allowable actions were specifically provided in the January 8, 2013 webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf ). No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. As shown by
this approval, the SDT and the industry disagree that there is a technical irregularity in Table 1. The Board of Trustees has also
previously approved this proposed standard. Discussions on the applicability of footnote 12 in that standard were held during
Project 2006-02 and are not part of this proceeding. No change made.
Public Utility District No. 2 of Grant
County, WA

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

GCPD abstains from voting on the revisions to footnote "b" in TPL-002-1c
and the corresponding footnote 12 of TPL-001-2. GCPD is concerned that
the revised language oversteps the bounds of the "reliability standard"
12

Organization

Yes or No

Question 1 Comment
definition under Section 215 of the Federal Power Act and into customer
service issues that are better served by, and under the jurisdiction of,
state and local utility boards and commissions. However, in the spirit of
moving this process forward, GCPD did not vote against the revised
footnotes.

Santee Cooper

No

Santee Cooper will abstain from voting on the revisions to footnote "b" in
TPL-002-1c and the corresponding footnote 12 of TPL-001-2. Santee
Cooper is concerned that the revised language oversteps the bounds of
the "reliability standard" definition under Section 215 of the Federal
power Act and into customer service issues that are better served by,
and under the jurisdiction of, state and local utility boards and
commissions. However, in the spirit of moving this process forward,
Santee Cooper will not vote against the revised footnotes.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Hydro One Networks Inc.

No

In this comment period Hydro One would like to reiterate its initial
comments.
Hydro One disagrees with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected
bulk electric system, the effect on customers of a firm demand
interruption is the responsibility of the applicable regulatory authority or
its delegated agencies responsible for local transmission and retail

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

13

Organization

Yes or No

Question 1 Comment
service over the load to be curtailed.
If it is decided to proceed with the 75 MW or any other value, we
propose replacing the sentence, in the footnote and in attachment one,
section III that reads:”In no case can the planned Non-Consequential
Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a non-US Registered Entity should be
determined by the applicable Regulatory Authority or Governmental
Authority or its delegated agency in that is responsible for retail electric
service issues in that jurisdiction.”

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
NARUC

No

As stated before, if there is no reliability threat to the bulk system there
is no need for the 75 MW limit on the anticipated amount of load to be
shed. As long as the regulator responsible for the retail load subject to
being shed is notified of the situation, the situation can be appropriately
addressed at the local level.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these
orders mandate the ERO to write standards and requirements to address all aspects of BES operations and reliability in support of
these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC
directives on this matter. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

14

Organization

Yes or No

SCE&G

No

Question 1 Comment
Comments previously submitted.

Response: Thank you for following the guidelines. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Independent Electricity System Operator

No

Please note that the Independent Electricity System Operator (IESO), an
RTO/ISO registered under Industry Segment 2, has filed an appeal with
respect to NERC’s response to our similar comments submitted to the
previous ballot on this project.
We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread adverse effect on the reliability of the interconnected
bulk power system, the effect on customers of a firm demand
interruption is the responsibility of the applicable regulatory authority or
its agencies responsible for local transmission and retail service over the
load to be curtailed.
To recognize NERC’s role as the ERO for Ontario and the Memorandum of
Understanding between NERC and the Ontario Energy Board, the IESO
proposed replacing the sentence, in the footnote and in attachment one,
section III that reads:”In no case can the planned Non-Consequential
Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is a Canadian
Entity (or a Mexican Entity) should be implemented in a manner that is
consistent with/or under the direction of the Applicable Governmental
Authority or its agency in Canada (or Mexico).Under this language, both
the amount of non-consequential load loss, and the process under which
that amount was arrived at, including stakeholder consultations, would
be determined by the relevant Canadian jurisdiction, in this case Ontario.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

15

Organization

Yes or No

Question 1 Comment
This change will make the standard acceptable in Ontario’s legislative
framework, in which NERC standards come into force automatically
unless, by order of the Ontario Energy Board, a standard is stayed and
remanded back to NERC for further consideration.
The responses to the IESO’s comments in the previous ballot were
inaccurate as to this key feature of the Ontario reliability framework, as
addressed in the IESO appeal. An alternate solution to this issue, which
would o be consistent with the intent of the responses to the IESO
comments on the previous ballot, o respect the Ontario reliability
framework, and o resolve the IESO January 9, 2013 appeal; and is
appropriate given that these changes are being driven by a U.S. FERC
remand order to NERC, would be to make the following highlighted
clarifications to footnotes ‘b’ and 12:With respect to Standard TPL-002-1c
- footnote ‘b’ b) An objective of the planning process is to minimize the
likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is
allowed 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 the shedding of any Firm Demand. It is recognized that Firm For
purposes of this footnote, the following are not counted as Firm Demand
will be interrupted if itt is: (1) Demand directly served by the Elements
removed from service as a result of the Contingency, or and (2)
Interruptible Demand or Demand-Side Management Load. In limited
circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met.
However, for U.S. registered entities when interruption of Firm Demand
is utilized within the Near-Term Transmission Planning Horizon to
address BES performance requirements, such interruption is limited to

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

16

Organization

Yes or No

Question 1 Comment
circumstances where the use of Firm Demand interruption meets the
conditions shown in Attachment 1. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW for U.S.
registered entities. With respect to Standard TPL-001-2a - footnote
12:12. An objective of the planning process is to minimize the likelihood
and magnitude of Non-Consequential Load Loss following Contingency
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, for U.S. registered entities
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 U.S. registered entities.

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of Texas, Inc.

No

See response to question 4.

No

1. In the last submittal for comments, the following comment was made:
It was not clear how transmission projects with long lead times (such as
T-lines) would be handled by “Footnote b.” In other words, it is not clear

Response: See response to Q4.
Tri-State G&T

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

17

Organization

Yes or No

Question 1 Comment
if it is acceptable for a TP to plan for shedding Firm Demand in the Near
Term Planning Horizon without meeting the conditions shown in
“Attachment 1” when a mitigating project is planned that cannot be
constructed in the Near Term Planning Horizon. The Standard Drafting
Team (SDT) provided the following response: Any instance of proposed
load shed for a single Contingency situation in a Planning Assessment
must meet the conditions of footnote ‘b.’ No Change made. From the
above comments, we believe there is a situation where the Bulk Electric
System (BES) reliability is compromised while stakeholder process
proceeds.

Response: This standard ensures these items are addressed in planning prior to them becoming an issue in operations so the SDT
believes that BES reliability is not being compromised. No change made.
Western Area Power Administration Transmission Owner

No

While Western generally agrees with the proposed modification to
footnote b, Western does not support the 75 MW threshold and
Attachment 1 Stakeholer process. The 75 MW threshold seems to low
and if a threshold it needed the drafting team should consider using a
300 MW threshold similar to that used in CIP-002, EOP-004, DOE OE-417
reporting, and NERC event analysis process.
The stakeholder process seems to be duplicative, considering there FERC
Order 890 planning process.

WAPA-RMR

No

While Western agrees in general with what is proposed in Footnote b; I
do not agree with stipluating 2 requirements in the proposed Footnote b:
The 75 MW load threshold; the Attachment 1 Stakeholder process. The
75 MW seems low and NERC should condsider using a 300 MW threshold
similar to that used in CIP-002 and EOP-004 requirements.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to 75 MW as a
reasonable limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The SDT used the
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

18

Organization

Yes or No

Question 1 Comment

Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it contained a
stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria for allowing
curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail and
specificity to the already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in Reliability
Standards and both mechanisms have been used before. No change made.
The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to allow an
entity to use an existing process as long as it meets the requirements shown in Attachment 1. No change made.
Massachusetts Attorney General

No

The SDT ignored a lot of feedback concerning the inappropriateness of a
75 MW threshold. IT remains inappropriate and an appropriate level
should be decided by local stakeholder processes.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The proposed solution allows
for input and participation at every step of the process by local jurisdictional authorities. In Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Entergy Services, Inc. (Transmission)

No

Attachment 1 is overly burdensome and concerns local reliability issues
better left to local regulators.
A planned or unplanned loss of 25 MW is inconsequential to the
reliability of the BES. The footnote could be simplified to exclude
attachment 1 as follows: An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency planning events. In limited circumstances, NonConsequential 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

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

19

Organization

Yes or No

Question 1 Comment
performance requirements, such interruption is limited to 25 MW and
notice must be given to applicable regulatory authorities or governing
bodies responsible for retail electric service issues within 30 days of the
completion of the assessment which includes the use of footnote 12.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that involve BES operations and reliability and the proposed
footnote ‘b’ solution acknowledges that fact and is an appropriate response to subsequent FERC directives on this matter. No change
made.
The SDT disagrees that Attachment 1 is overly burdensome as it simply addresses items that would be part of a Transmission
Planner’s normal workload. No change made.
As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The current
proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to be
supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Consolidated Edison Co. of NY, Inc.

No

Planned interruptions of Firm Demand in response to a Single
Contingency (as directed in Footnote b of TPL-002 Table 1, and Footnote
12 of TPL-001-2), is not an acceptable corrective action to mitigate
reliability issues on the BES system. The Interconnected System should
be designed and operated with enough transfer capacity to be able to
withstand, at a minimum, a single contingency event without service
interruptions to customer load. Systems must be designed and operated
so that the impact of any single contingency can be mitigated by redispatching available system resources without the need to implement
load shedding.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

20

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Yes or No

SDG&E

No

Question 1 Comment
Table 1, footnote b of TPL-002 allows the use of load shedding for the
loss of a single element (Category B) under certain circumstances. SDG&E
has been against the proposed changes because of the addition of a
stakeholder process that allows outside entities to make reliability
decisions which we would be held accountable for.

Response: The SDT believes that the described process allows for open and transparent discussion of the potential use of footnote
‘b’ in the planning environment and disagrees that anything in the proposed footnote provides outside entities with the ability to
make reliability decisions. No change made.
Platte River Power Authority

No

Disagree with no change to the 75 MW threshold, but agree with the
minor changes that were made since last posting. I request your
consideration of a 300 MW threshold similar to that used in CIP-002 and
EOP-004. Since there is a directive for some threshold, and in an attempt
to reduce the likelihood of over-burdening smaller communities, the 300
MW level would be a more reasonable threshold for the BES.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. No change made.
ISO New England Inc

No

There are jurisdictional issues with the footnote and attachment as
written. These will be described in further detail throughout this
document.
The footnote itself states, “An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following planning events.” A standard should not have requirements
described as objectives, this language is extremely subjective.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

21

Organization

Yes or No

Question 1 Comment

of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
The SDT does not believe that the stated objective serves as a requirement. No change made.
MISO

No

ITC

MISO does not object to the changes made to the body of the footnote
since the previous draft.
However, as a general matter, MISO cannot support the current language
of Footnote 12. Because the intent of the TPL standards is not to rely on
non-consequential firm load shedding after a single contingency event,
MISO does not agree that footnote b in NERC TPL-002-1 and/or footnote
12 in TPL-001-2 should be included in these standards.

JDRJC Associates LLC

Nonetheless, if these footnotes are included, MISO agrees that there
should be some limitation on how much firm load shed is allowed under
these footnotes and would not object to the proposed 75 MW level if the
footnotes are included.
Response: Thank you for your support.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Northeast Utilities

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Northeast Utilities does not support the use of non-consequential
demand interruption throughout the planning horizon. Even with the 75
MW limit, NU believes that this language seems to encourage
operational workarounds and adds burdens for operators of the system.
Lastly, NU believes this use of non-consequential load loss during the
planning horizon is not consistent with planning a highly reliable bulk

22

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Yes or No

Question 1 Comment
electric system and thus does not support non-consequential load loss
for planning purposes.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.
Hydro-Quebec TransEnergie

No

Hydro-Québec TransÉnergie (HQT) remains unconvinced that a MW
threshold needs to be part of footnote 12. This is not a BES reliability
issue but only a matter of service continuity to be addressed by
TO/PA/RC with local regulatory authorities.

Response: The SDT Believes that the FERC Orders made it clear that the concept of dropping Non-Consequential Load for a N-1
Contingency must include MW thresholds. The SDT has made a change to the main body of the footnotes to address the concerns of
non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Pacific gas and Electric Comapny

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We do not agree with the imposition of a maximum limit on the amount
of planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. Assigning a fixed “not to exceed” number of MW in
a continent-wide standard is overly prescriptive. A single number cannot
account for variation even within one BA Area. A fixed maximum number
of MW for Non-Consequential Load Loss under Footnote b in TPL-002
(and footnote 12 in TPL-001-3) is not necessary. The first sentence of this
footnote states, “[a]n objective of the planning process should be to
minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events”. It is clear that the spirit
23

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Yes or No

Question 1 Comment
of the TPL Standard is to minimize the likelihood and magnitude of Firm
Demand interruption. Adding a fix maximum number of MW would
seem unnecessary at best. At worst, it could have unintended
consequences. Without a fixed maximum Non-Consequential Load Loss,
the Transmission Planner understands that the objective is to minimize
the magnitude of the planned interruption under footnote b (TPL-001-3,
footnote 12). Adding a maximum number of MW of planned Firm
Demand loss could have the effect of giving “safe harbor” to allow
planned loss of that amount of load under Footnote b. The Transmission
Planner may now have more difficulty in avoiding Non-Consequential
Firm Demand Loss that is less than the “not to exceed” amount.

Response: The development of a standard that allowed for the use of footnote ‘b’ without quantifiable criteria was not acceptable to
FERC as shown in the Remand Order. There is no ‘safe harbor’ up to the identified limit since it will be discussed in an open and
transparent stakeholder process that includes applicable regulators. No change made.
ACES Standards Collaborators

Yes

Brazos

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) We continue to disagree with the 75 MW capacity limit threshold.
There is no need for a 75 MW cap because registered entities and locallevel policy makers are in the best position to determine an appropriate
capacity limit, as stated in the FERC order and in previous feedback.
However, if the drafting team decides to move forward with a cap, we
suggest using a cap that would reflect all data points from the Section
1600 data request to be under the threshold. The findings to the data
request contained a data point at 75.2 MW, which would be over the
proposed threshold. We understand this data point, in essence, has
been omitted because the use of non-consequential load shedding for
the 75.2 MW data point is expected to terminate soon. If the drafting
team intends to use the data that represents the actual usage of
footnote ‘b’ by planning coordinators, then the team should take into
account the highest data point and adjust the threshold to at least 76
MW regardless of the length of time the data point is needed. Again,
24

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Yes or No

Question 1 Comment
local decision makers are better equipped to make this type of
determination.
(2) However, in the spirit of moving forward with this project we will
support the changes and thank the drafting team for their efforts.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these
orders mandate the ERO to write standards and requirements to address all aspects of BES operations and reliability in support of
these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC
directives on this matter. The SDT established the limit based on the results of the Section 1600 data request which clearly pointed
to a 75 MW limit. While the SDT considered a higher limit value, the data collected does not justify such an action. No change made.
Thank you for your support.
Georgia Transmission Corp.

Yes

Since this question refers to both footnote b (TPL-002-1c) and footnote
12 (TPL-001-2a), and the changes to the footnotes are not identical, the
question should be split into two.
Regarding footnote b: An excerpt from footnote b reads “For purposes of
this footnote, the following are not counted as Firm Demand (1) Demand
directly served by the Elements removed from service as a result of the
Contingency ...” However, what is being described is in fact Firm
Demand (That portion of the Demand that a power supplier is obligated
to provide except when system reliability is threatened or during
emergency conditions) that is Consequential Load Loss (All Load that is
no longer served by the Transmission system as a result of Transmission
Facilities being removed from service by a Protection System operation
designed to isolate the fault.). Therefore, why not use the terms
Consequential Load Loss and Non-Consequential Load Loss?
Regarding footnote 12: The replacing the NERC defined “Contingency”
event with the undefined “planning” event necessitates a new definition.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

25

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Yes or No

Question 1 Comment
The intent of the change is unclear.

Response: The issue is one of timing. The indicated terms are part of the proposed TPL-001-2 solution and were not in existence
when TPL-002-1 was developed. Since the SDT cannot control how FERC will respond to the proposed solutions to this project, it is
possible that TPL-002-1 could be approved prior to TPL-001-2. This would create considerable confusion as to the use of these terms.
Therefore, the SDT wrote the proposed solutions separately. No change made.
The wording change now makes the terminology consistent in both Table 1 and the text. No change made.
Manitoba Hydro

Yes

SERC EC Planning Standards Subcommittee

Yes

Southwest Power Pool Reliability
Standards Development Group

Yes

Manitoba Hydro agrees that the changes add clarity to the footnote.

Kansas City Power & Light

Bonneville Power Administration

Yes

MRO NSRF

Yes

Duke Energy

Yes

TVA Transmission Reliability Engineering
and Controls

Yes

Southern Company

Yes

American Electric Power

Yes

Ameren

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

26

Organization

Yes or No

Idaho Power Company

Yes

Tacoma Power

Yes

ITC

Yes

Oncor Electric Delivery Company LLC

Yes

Question 1 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

27

2.

Do you agree with the changes contained in Section II of Attachment 1? If you do not support these changes or you agree in
general but feel that alternative language would be more appropriate, please provide specific suggestions in your comments

Summary Consideration: The SDT has responded to the individual comments and there are no changes proposed to the standards as a
result of comments.
Organization

Yes or No

ACES Standards Collaborators

No

Brazos

Question 2 Comment
(1) Thank you for making the changes to Section II of Attachment 1. We believe the
modification of removing “assessments” and replacing it with “explanation”
provides more flexibility regarding how a registered entity can demonstrate the
impacts the health, safety and welfare of the community.
(2) However, we still believe that the word “alleviate” in bullet 5 requires the same
actions as the word “mitigate.” There are instances where no action is required
based on a variety of factors. We recommend the following: “Future plans, if
necessary, to mitigate/alleviate the need for Non-Consequential Load Loss under
footnote 12, unless a determination was made not to mitigate/alleviate, then an
explanation why.”

Response: Thank you for your support.
This is an information section and not a requirement for a more permanent solution. Therefore, if there is no plan to alleviate then
an entity simply documents that fact. No change made.
MRO NSRF

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

The drafting team over specified the Section II stakeholder information process and
continues to disregard comments that item 2b be removed from several utilities
over several footnote “b” revisions. The goal of Attachment 1 as stated by the
drafting team chair was to place “meaningful” parameters around footnote b. The
words in 2b on “health, safety, and welfare” are beyond the scope of NERC
standards, and are not defined sufficiently in the standard to make the

28

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Yes or No

Question 2 Comment
requirement meaningful. The NSRF recommends that if the drafting team doesn’t
eliminate 2b, they delete the words “on the health, safety, and welfare of the
community” as going beyond NERC jurisdiction, FERC directives, and the SAR. The
drafting team response that similar words exist in another standard is not a reason
to the ambiguous words in the TPL Attachment 1.

Response: The SDT did not justify the retention of the subject phrase simply because similar words exist in another standard but
because the burden and intent of the phrase in footnote ‘b’ is consistent with what entities are required to do in that other standard
(the phrase is included in EOP-001 as part of a description of Load curtailment in Attachment 1 of EOP-001, which describes elements
for consideration in developing emergency plans). The SDT believes that the changes made in this posting clarify the intent of this
requirement. No change made.
Hydro One Networks Inc.

No

As previously stated, we believe that the process presented in Section II is overly
prescriptive.
If a section that prescribes the information requirements for a stakeholder process
is required, then for non-US entities this section should simply require that the
process information requirements must be in accordance with the requirements of
the applicable Regulatory Authority or Governmental Authority or its delegated
agency that is responsible for local transmission and retail service in that
jurisdiction.

Independent Electricity System
Operator

No

No. The process presented in Section II is overly prescriptive.
If a section that prescribes the information requirements for a stakeholder process
is required, then for Canadian entities this section should simply state that any
threshold should be established in a manner consistent with other service levels
that apply to local transmission and retail service for the load to be curtailed, for
the reasons described in Q1.

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

29

Organization

Yes or No

Question 2 Comment

‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Tri-State G&T

No

2. As stated previously, NERC Functional Model definitions for Planning Authorities
and Transmission Planners do not include the types of activities being proposed in
“Attachment 1.” As written, this standard mandates functions on functional entities
that are outside those defined by the NERC Functional Model. The SDT
acknowledged this by stating that “the NERC Functional Model is a guideline for
activities required of cited functional entities.”As such, we still believe that
obligations should not be required of entities outside of the NERC Functional Model
descriptions.

Response: The SDT stands by its previous response to this comment posted for the comment period ending November 19, 2012.
SCE&G

No

Comments previously submitted.

Response: Thank you for following the guidelines. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of
Texas, Inc.

No

See response to question 4.

No

Attachment 1 is overly burdensome and unnecessary.

Response: See response to Q4.
Entergy Services, Inc.
(Transmission)

Response: The SDT believes that Attachment 1 is an appropriate response to the FERC Orders. Without specifics the SDT is unable to
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

30

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Yes or No

Question 2 Comment

provide a more detailed response to your concerns. No change made.
Manitoba Hydro

No

Any assessment or explanation is only speculation. Is the requirement any
different?
Item 5 raises an expectation that footnote 12 can only be used on an interim bases
- this should be clarified.

Response: The SDT believes that the changes made in this posting clarify the intent of this requirement. No change made.
The SDT believes that, in general, the use of footnote ‘b’ to meet TPL performance requirements should be an interim solution.
However, in certain circumstances, the SDT realizes that the solution may be permanent. The SDT does not believe that the wording
only allows for interim use. If the solution is to be permanent, then that information should be disclosed as part of the stakeholder
process. No change made.
ISO New England Inc

No

Section II, 2.a, states that studies must address the estimated number and type of
customers affected by Non-Consequential Load Shedding. The Transmission
Planner in many cases will not be the appropriate entity to address these concerns.
The Transmission Owner, Distribution Provider or Load Serving Entities would be
the appropriate entities to address customer affects.
Explaining effects on the “health, safety, and welfare of the community” is required
under the footnote in Section II, 2.b. The same load could be shed directly as the
consequence of a fault and no such assessment is required. In addition,
Transmission Planners can shed radial load with no assessment of health and
welfare.
In addition to the practical considerations listed, once again here the standard
infringes on Section 215 responsibilities where State authority over the “safety,
adequacy and reliability of the electric system in that state” is mandated. This
section should be deleted.
Section II, requirements 3 and 4 discuss estimating frequency and duration of
Non-Consequential Load Loss based on historical performance. The planning

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

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Question 2 Comment
process uses deterministic not probabilistic assessments. This section should be
deleted.

Response: The SDT believes that the indicated information is easily obtained by the Transmission Planner and that, in some cases,
the Transmission Planner may already have this information for other tasks and responsibilities. No change made.
The SDT agrees that such information is not required in other circumstances involving allowed Consequential Load Loss. However,
this situation is different in that it involves Non-Consequential Load Loss. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of footnote ‘b’.
No change made.
MISO

No

ITC
JDRJC Associates LLC

Regarding the use of “explanation” in place of “assessment,” MISO understands
that the purpose of this change is to reduce the need for entities to hire expensive
consultants and to incur other substantial costs in assessing demographic data and
impacts on an affected area. However, as written, this word change potentially
places more of a burden on responsible entities. An assessment is an analysis
performed using available facts and data while an explanation implies full
knowledge. MISO therefore recommends that “assessment” be retained and that a
footnote explaining the meaning of that term be added.
More generally, however, MISO has concerns regarding the use of a stakeholder
process such as the one outlined in Attachment 1 and cannot support the Footnote
or Attachment 1 at this time. Please refer to our comments under Question 4 for a
more detailed description of these concerns.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

32

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Yes or No

Question 2 Comment

Response: The SDT believes that the changes made in this posting clarify the intent of this requirement. No change made.
Please see response to Q4.
Pacific gas and Electric Comapny

No

Suggest removing item 5, “A dispute resolution process for any question or concern
raised in #4 above that is not resolved to the stakeholder’s satisfaction”. Given that
the “applicable regulatory authorities or governing bodies responsible for retail
electric service issues” are only one of the many affected stakeholders, it is unclear
how this dispute resolution process would treat stakeholders with different
concerns. For example, how would such a dispute resolution process take into
account the cost-benefit balance of load loss, which is the responsibility of the
authorities responsible for retail rates, if such an authority is only one of the many
stakeholders subject to dispute resolution?

Response: Bullet #5 does not require specific attributes of the dispute resolution process. The SDT believes that the attributes of the
dispute resolution process should be defined by the entity during the development of the stakeholder process. No change made.
SDG&E

No

Response: Without a specific comment, the SDT is unable to respond.
SERC EC Planning Standards
Subcommittee

Yes

Northeast Power Coordinating
Council

Yes

Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

33

Organization

Yes or No

Bonneville Power
Administration

Yes

Duke Energy

Yes

TVA Transmission Reliability
Engineering and Controls

Yes

Western Area Power
Administration - Transmission
Owner

Yes

Southern Company

Yes

Massachusetts Attorney General

Yes

American Electric Power

Yes

Ameren

Yes

WAPA-RMR

Yes

Idaho Power Company

Yes

Platte River Power Authority

Yes

Tacoma Power

Yes

ITC

Yes

Georgia Transmission Corp.

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Question 2 Comment

34

Organization

Yes or No

Oncor Electric Delivery Company
LLC

Yes

Question 2 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

35

3.

Do you agree with changes contained in Section III of Attachment 1? If you do not support these changes or you agree in general
but feel that alternative language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT has responded to the individual comments and there are no technical changes proposed to the
standards as a result of comments. However, to avoid confusion, the SDT has deleted the duplicative statement in Section III regarding
the 75 MW limit. And, the SDT made a grammatical change in Section III changing ‘does’ to ‘do’ to correct the grammar in the applicable
sentences.
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail electric service issues does not object …”
Organization

Yes or No

MRO NSRF

No

Question 3 Comment
The NSRF believes that the standards drafting team did clarify in the webinar that
the 25 MW and 75 MW footnote “b” values were separate from interruptible load,
and consequential load loss and would not be counted towards the 25 and 75 MW
thresholds. However, the NSRF recommends that Attachment 1 also clearly
contain an explicit statement “the 25 MW and 75 MW footnote “b” values are
separate from consequential load loss, interruptible load, and are not to be
counted towards the 25 MW and 75 MW thresholds.”

Response: The SDT does not believe that this suggestion adds any clarity. No change made.
Hydro One Networks Inc.

No

The process presented in Section III is overly prescriptive and duplicates
information not necessary for its intended purpose.
As stated in Q1, we disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard, and propose alternate
language in our response to Q1.
If this section is required to address a review of the use of footnote 12 to ensure
that there are no wide-spread adverse reliability impacts on the bulk power system,
then it should be limited to the information required for that purpose. Provided
there is local support for the use of Non-Consequential Load Loss under footnote

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

36

Organization

Yes or No

Question 3 Comment
12, only information items 6 and 8 from section II are relevant for this assessmentthe remainder are not required for this section and should be deleted. Items 1 and
2 complicate this section and are unnecessary. They should be replaced by a
phrase such as “for those planning events where the use of footnote 12 is
referenced.” We disagree with the need to submit this information to the ERO for a
determination of whether there are any Adverse Reliability impacts caused by the
use of Non-Consequential Load Loss. This will introduce a new type of review at
the ERO that will create unnecessary delays and burden, and is inconsistent with
(and not required for) all of the other performance requirements in the TPL
standards. Submitting the analysis to the adjacent Planning Coordinators and
Transmission Planners, and any functional entity that requests it, as called for in
requirement R8 of TPL-001-2 should be sufficient.

Response: The SDT does not believe the section is overly prescriptive or duplicative as described below. No change made.
Please see response to Q1.
The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of footnote ‘b’.
If local regulators require additional information they can always request it. While the ERO may not need all of the information in
Section II to perform its Adequate Reliability Impact evaluation, the SDT wanted to minimize the burden on entities by allowing the
submittal of an information package that already existed. The ERO is aware of the proposed responsibility and has accepted this role
if the industry approves. The SDT believes that it is the responsibility of the ERO to assess Adverse Reliability Impacts and is not an
appropriate role for adjacent planners. No change made.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of
Texas, Inc.

No

See response to question 4.

MISO

No

MISO does not object to the changes made to Section III. However, more generally,
MISO has concerns regarding the use of a stakeholder process such as the one
outlined in Attachment 1 and cannot support the Footnote or Attachment 1 at this

ITC

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

37

Organization

Yes or No

JDRJC Associates LLC

Question 3 Comment
time. Please refer to our comments under Question 4 for a more detailed
description of these concerns.

Response: See response to Q4.
Tri-State G&T

No

3. Previously, it was commented that it is unclear how section III of “Attachment 1”
would be applied to entities that only deliver wholesale electric service and not
retail electric service. The response provided by the SDT stated the following: The
SDT believes that the wholesale customer will be one of the stakeholders included
in the process and any use of footnote must go through the stakeholder process.
No change made. If the wholesale customer is one of the stakeholders, the
standard needs to add wholesale customers into the language as part of
Attachment I. For example, it should read as follows: Coordinator must ensure that
the applicable regulatory authorities, wholesale customers, or governing bodies
responsible for retail electric service issues does not object to the use of Firm
Demand interruptions under footnote ‘b’...

Response: The SDT believes that the planning entity has the best understanding of who an affected stakeholder will be and that any
attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a
one size fits all approach. No change made.
Western Area Power
Administration - Transmission
Owner

No

See answer to Question 1.

WAPA-RMR

No

See response to Question 1.

Platte River Power Authority

No

See answer to Question 1.

Response: See response to Q1.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

38

Organization

Yes or No

Massachusetts Attorney General

No

Question 3 Comment
Don't buy the 75 MW or the 25 MW thresholds.

Response: The SDT established the values based on the results of the Section 1600 data request. While the SDT considered other
values, the data collected did not justify such an action. No change made.
Entergy Services, Inc.
(Transmission)

No

Attachment 1 is overly burdensome and unnecessary.

Response: With no specifics provided, the SDT is unable to respond further. However, the SDT does not believe the process to be
overly burdensome or unnecessary. No change made.
SCE&G

No

Comments previously submitted.

Response: Thank you for following the guideline. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Independent Electricity System
Operator

No

The process presented in Section III is overly prescriptive and requires information
not necessary to the intended purpose.
As stated in Q1, we disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard, and propose alternate
language as stated in Q1 comments and supporting reasons. If this section must
deal with a review of the use of footnote ‘b’/’12’ to ensure that there are no
widespread adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local
support for the use of Non-Consequential Load Loss under footnote ‘b’/’12’, only
information items 6 and 8 from section II are relevant for this assessment-the
remainder are not required for this section and should be deleted.
The use of footnote ‘b’/’12’ should not be limited to the Near-Term Planning
Horizon. We propose that the words “in Year One of the Planning Assesssment” be
deleted.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

39

Organization

Yes or No

Question 3 Comment
Items 1 and 2 complicate this section and are unnecessary. They should be
replaced by a phrase such as “for those planning events where the use of footnote
‘b’/’12’ is referenced”.
We disagree with the need to submit to the ERO for a determination of whether
there are any adverse reliability impacts caused by the use of Non-Consequential
Load Loss. This will introduce a new type of review at the ERO that will create
unnecessary delays and burden, and is inconsistent with and not required for all of
the other performance requirements in the TPL standards. Submitting the analysis
to the adjacent Planning Coordinators and Transmission Planners, and any
functional entity that requests it, as called for in requirement R8 of TPL001-2
should be sufficient.

Response: The SDT does not believe the section is overly prescriptive or duplicative as described below. No change made.
Please see response to Q1.
The use of the footnote is not limited to the Near-Term Transmission Planning Horizon since the main body of the footnote states
that the footnote may be utilized “… throughput the planning horizon…”. An entity has the freedom to make a business decision
concerning the use of footnote ‘b’ compared to other alternatives. An entity is free to determine when they want to assure that the
local regulator does not object but it must do so no later than Year One of the Planning Assessment. No change made.
The SDT believes that items 1 and 2 are needed to describe when an entity must assure that there are no regulatory objections. No
change made.
While the ERO may not need all of the information in Section II to perform its Adequate Reliability Impact evaluation, the SDT wanted
to minimize the burden on entities by allowing the submittal of an information package that already existed. The ERO is aware of the
proposed responsibility and has accepted this role if the industry approves. The SDT believes that it is the responsibility of the ERO to
assess Adverse Reliability Impacts and is not an appropriate role for adjacent planners. No change made.
Pacific gas and Electric Comapny

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We disagree with the inclusion of the information in Section II.2.a (the estimated
number and type of customers affected) and II.2.b (An assessment of the use of
Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community). We suggest removing them. Section II.2.a is an administrative
40

Organization

Yes or No

Question 3 Comment
process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It
can also become a legal liability issue for the service provider, even if that loss of
load is judged to be a prudent decision by the “applicable regulatory authorities or
governing bodies responsible for retail electric service issues”.

Response: The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of
footnote ‘b’. No change made.
SDG&E

No

Response: Without a specific comment, the SDT is unable to respond.
ISO New England Inc

The footnote states “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 does not object to the use of Non-Consequential Load Loss
under footnote 12 if either...”. Section 215 of the Federal Power Act clearly
delineates Federal, State and Local authority. State and Local requirements should
not be introduced into a NERC standard. In addition to the jurisdictional issues,
proving that the “applicable regulatory authority or governing body” does not
object is more difficult than proving that they simply approved the use of nonconsequential load loss. The SDT should remove all references to State and Local
authority from the standard.
Overall, the order of Section III is also notable. During year, two through ten of the
overall planning horizon the standard allows for Non-Consequential Load Loss
without approval. In the first year of the assessment, approval becomes required
for Non-Consequential Load Loss. At this point, it is too late to allow for any other
alternative.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

41

Organization

Yes or No

Question 3 Comment
The Regional Entities with NERC oversight perform periodic audits and require selfcertification of the planning process. By virtue of the audit and self-certification
process, NERC has the ability to monitor the use of Non-Consequential Load Loss in
planning assessments. State and Local approval of practices called for in ERO
Standards is inappropriate.
In addition to being notable for the year one timing, Section III seems incomplete.
In the case where there is objection to Non-Consequential Load Shedding, the
process appears to end without resolution.

Response: In Order 693, FERC clearly stated that it has jurisdiction over matters that involve BES operations and reliability.
Furthermore, these orders mandate the ERO to write standards and requirements to address all aspects of BES operations and
reliability in support of these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to
subsequent FERC directives on this matter. The footnote does not place requirements on local regulators but rather provides them
an opportunity to participate in the stakeholder process. No change made.
An entity has the freedom to make a business decision concerning the use of footnote ‘b’ compared to other alternatives. An entity
is free to determine when they want to assure that the local regulator does not object but it must do so no later than Year One of the
Planning Assessment. No change made.
Without the details now contained in the proposed footnote, there is no guarantee that NERC would have the information to
monitor the use of Non-Consequential Load Loss. The footnote does not place requirements on local regulators but rather provides
them an opportunity to participate in the stakeholder process. No change made.
If there is an objection by the regulators, then an entity cannot utilize footnote ‘b’ as proposed as part of the Corrective Action Plan
for Year One. No change made.
Ameren

Yes

We find no substantive changes to section III, and still believe that no objection
from a regulatory body requires, at a minimum, a tacit approval.

Response: The SDT believes that there are a variety of practices employed by regulatory bodies. Therefore, it is determined by the
planning entity and the applicable regulatory bodies as to how to show ‘no objection’. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

42

Organization

Yes or No

SERC EC Planning Standards
Subcommittee

Yes

Question 3 Comment
Change "does" to "do" in the last sentence of the first paragraph and in the first
sentence of the last paragraph in Section III of Attachment 1.

Response: The SDT agrees and has made the suggested grammatical change.
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail electric service issues does not
object …”
Northeast Power Coordinating
Council

Yes

Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light

Bonneville Power
Administration

Yes

ACES Standards Collaborators

Yes

Brazos
Duke Energy

Yes

TVA Transmission Reliability
Engineering and Controls

Yes

Southern Company

Yes

American Electric Power

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

43

Organization

Yes or No

Idaho Power Company

Yes

Tacoma Power

Yes

ITC

Yes

Georgia Transmission Corp.

Yes

Oncor Electric Delivery Company
LLC

Yes

Question 3 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

44

4.

If you have any other comments on this Standard that you haven’t already mentioned above, and that are not simply
reiterating previous comments that the SDT has already responded to, please provide them here:

Summary Consideration: The SDT has responded to the individual comments and there are no changes proposed to the standards as a
result of comments. However, the SDT did uncover a typo that has been corrected as shown below.
TPL-002-1c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as Firm Demand t: (1) …”
Organization

Yes or No

Hydro-Quebec TransEnergie

No

Question 4 Comment
HQT still considers that the non application of footnote 12 to categories P2 (breaker
fault), P4 (stuck breaker) and P5 (failure of a non redundant relay) is not correct,
when the footnote is applied to other categories such as P3, P6 and P7 (loss of
double-circuit lines). The SDT has indicated that the applicability of footnote 12 to
categories P2, P4 and P5 is not included in Project 2012-11. However, looking at
related Project 2006-02 where footnote 12 was brought up to Table 1, the matter of
applicability was not discussed in detail and the SDT did not clearly explain why
Non-Consequential Load Loss was not allowed for contingencies less frequent than
those for which it is allowed (internal breaker faults or stuck breakers are less
probable than double-circuit line faults). Discussion on this matter should not be
dismissed.

Response: Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. The
Board of Trustees has also previously approved this proposed standard. Discussions on the applicability of footnote 12 in that
standard were held during Project 2006-02 and are not part of this proceeding. No change made.
Bonneville Power
Administration

No

Duke Energy

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

45

Organization

Yes or No

American Electric Power

No

SDG&E

No

Idaho Power Company

No

Platte River Power Authority

No

SCE&G

No

Oncor Electric Delivery
Company LLC

No

Pacific gas and Electric
Comapny

No

Question 4 Comment

Response: Without a specific comment, the SDT is unable to respond.
ACES Standards Collaborators

Yes

Brazos

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) In regard to the changes relating to Demand-Side Management, we agree with
the wording, “For purposes of this footnote, the following are not counted as Firm
Demand: (1) Demand directly served by the Elements removed from service as a
result of a Contingency, or (2) Interruptible Demand or Demand-Side Management
Load.” However, the most recent change has created some confusion by replacing
“or” with “and” that potentially and inadvertently may exclude the use of DSM in all
locations but on the facilities removed from service. This would render DSM
ineffective. Now, the both (1) and (2) must occur in order to not be counted as Firm
Demand. We recommend changing the wording back to “or” so each option (1) OR
(2) is independently excluded from Firm Demand for footnote b. Connecting the
options with the word “and” changes the meaning and requires entities to meet
both option (1) and option (2) to be excluded from Firm Demand. Demand directly
served by the Elements removed from service as a result of a Contingency should be

46

Organization

Yes or No

Question 4 Comment
excluded, as should Interruptible Demand or Demand-Side Management Load
regardless of its location. A registered entity does not need to have both for the
exclusion.
(2) Thank you for the opportunity to comment.

Response: The SDT does not agree that ‘and’ excludes the use of both items 1 and 2 since this is a list of options. However, while
researching your suggestion, the SDT discovered a typo in the language when the previous red-line was converted to a clean copy.
This has been corrected as shown.
TPL-001-2c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as Firm Demand t: (1) …”
Hydro One Networks Inc.

Yes

As previously stated in our response to Question #1, Hydro One would like to
reiterate our position presented during the initial comment period. We believe that
the SDTs response to our initial comments did not correctly address the issues
because it did not recognize the Reliability Standards framework that is effective in
the Province of Ontario and possibly other Canadian provinces.

Response: Please see the response to Q1.
MISO

Yes

ITC
JDRJC Associates LLC

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

As previously stated, it is the general intent of the existing TPL-002-1 standard and
proposed TPL-001-2 standard to not rely on any shedding of Non-Consequenital
Load to meet a single contingency event. Accordingly, MISO submits that footnote
b of TPL-002-1 and footnote 12 of TPL-001-2 should be struck. However, in the
event that the footnotes in question are not eliminated, the footnote should be
narrowly focused only on those situations for which the original footnote was
developed, i.e., the interruption of service to radial customers or some local area
Network customers connected to or supplied by the Faulted element or by the
affected area, where the overall reliability of the interconnected transmission
system is not impacted. MISO therefore proposes the following alternate language
for footnote b and footnote 12 to ensure it is not misapplied:”An objective of the
planning process is to avoid Non-Consequential Load Loss following Contingency

47

Organization

Yes or No

Question 4 Comment
events. In limited circumstances, Non-Consequential Load Loss may be needed
within the planning horizon to ensure that BES performance requirements are
satisfied. However, Non-consequential Load shed cannot be used to avoid
cascading outages or to maintain system stability. Non-consequential load shed
also cannot be used to avoid a thermal loading or voltage limit violation on an extra
high voltage (EHV) facility. When Non-Consequential Load Loss is utilized within the
transmission planning horizon to address BES performance requirements, such
interruption cannot exceed 75 MW and is limited to the following circumstances: o
Non-consequential Load shed is allowed for load served by a radial transmission line
to avoid voltage limit violations on the radial transmission line following a single
contingency event. o Non-consequential load shed is allowed for load within a local
area served by not more than two Transmission Circuits and/or Transformers to
avoid a thermal loading issue or voltage issue within the local area, including the
Transmission Circuits and/or Transformers directly supplying the local area, for a
loss of a single element within the local area, including one of the Transmission
Circuits or Transformers directly supplying the local area, so long as there are no
thermal loading or voltage violations outside the local area.” MISO believes the
language above would ensure the continuing reliability of the Bulk Electric System
by limiting load shed and violations that require load shed to radial areas or areas
that would be served radially following the single contingency.
In addition, MISO has significant concerns regarding use of a stakeholder process to
determine if non-conseqeuntial load shedding is appropriate following a single
contingency event, as expressed in MISO’s comments on previous drafts of this
Project. In particular, MISO has concerns regarding whether such a stakeholder
process could be sufficiently open and transparent given the many, competing
interests of the responsible entity and affected stakeholders. Without such
sufficient openness and transparency, it is likely that stakeholder processes will not
result in consistent determinations of the appropriateness of the application of
footnote b in NERC TPL-002-1 and/or footnote 12 in TPL-001-2. Stated differently,
MISO is concerned that such stakeholder processes will always be subject to the

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

48

Organization

Yes or No

Question 4 Comment
biases of the participating parties, with the sheer number of parties determining the
outcome of the process. As an example, should a particular process be dominated
by parties that may be responsible for payment of upgrades but that are not
impacted by the alternative load shed, those stakeholders impacted by the
alternative load loss would be relegated to a minority position, resulting in majorityimposed stakeholder decisions to shed load. On the other hand, if the stakeholder
process is limited to only the stakeholders directly impacted by the proposed load
shed, to the extent those stakeholders pay only a small part of the upgrade costs,
they will always choose to avoid load shed - even if such decision requires a
potentially costly upgrade. Consequently, MISO has concerns that the inclusion of a
requirement for a fair and impartial stakeholder process to determine if and when
load shed is acceptable to assist in satisfying a single contingency standard is not
realistically attainable.
MISO therefore recommends that Attachment I be eliminated and that the
footnotes either be eliminated or replaced with the modified version above.

Response: The SDT believes that the suggested language adopts a one-size fits all approach that is not conducive to a continent-wide
standard. The footnote allows for circumstances outside of the suggested language scenarios, as well as those described in the
suggestion, to be resolved utilizing an open and transparent process. No change made.
The SDT believes that the inclusion of stakeholders including regulators provides an appropriate method for addressing the issues
that the commenter has raised. No change made.
BC Hydro

Yes

BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c System Performance Following Loss of a Single BES Element (footnote b) and TPL001-2a - Transmission System Planning Performance Requirements (footnote 12).
BC Hydro votes YES in support of this ballot and wishes to provide the following two
comments: 1.At this time BC Hydro has concerns about the level of stakeholder
consultation that might be required as a result of the implementation of this
standard and will bring this concern to the attention of our regulator if necessary.
2.At this time BC Hydro has concerns about the instances for which regulatory

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

49

Organization

Yes or No

Question 4 Comment
review of non-consequential load loss under footnote 12 is required and will discuss
those with our regulator if necessary.

Response: The SDT appreciates your overall support. In addition, please see the changes shown in Q1 for non-US registered entities.
Central Lincoln

Yes

Flathead

Central Lincoln has not paid much attention to this standard, since it is not
applicable to this entity's registered functions. However, we are disturbed by the
direction the standard is taking. The slides from the recent webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf)
state that "The 75 MW cap will require construction of major Transmission
projects." This is in direct conflict with the definition of "reliability standard" as
provided in section 215 of the FPA where it states "...the term does not include any
requirement to enlarge such facilities or to construct new transmission capacity..."
The webinar slide does offer alternatives to construction, but we don't see those
providing any reliability benefit. Some of the suggestions apparently only relate to
contract language, which cannot possibly relate in any way to "reliable operation"
as defined in section 215. Central Lincoln is is concerned that the revised language
oversteps the bounds of the "reliability standard" definition under Section 215 of
the Federal power Act and into customer service issues that are better served by,
and under the jurisdiction of, state and local utility boards and commissions.

Response: The statement from the January 8, 2013 webinar is a concern that industry had raised during the course of the project,
which the SDT had captured on a slide in order to respond to the concern during the webinar. The SDT pointed out that building is
not the sole source of remedy for the situation and provided specific examples in the webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf (slide 13)). In Order 693, FERC clearly stated that
it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Electric Reliability Council of
Texas, Inc.

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

ERCOT believes that the revisions to the footnote b attachment are an
improvement from the previous version. However, ERCOT does not believe that the

50

Organization

Yes or No

Question 4 Comment
SDT provided a technical rationale for disagreeing with the comments that we
previously submitted. We fundamentally disagree with the approach of defining a
stakeholder process in the attachment to a footnote in a reliability standard. While
footnotes and attachments have been used in other standards we believe that this
application is not appropriate.
ERCOT believes that the footnote should be removed altogether as it does not meet
the objectives of FERC Order 693. We also believe that FERC did not mandate that a
stakeholder process be used. As stated in the January 8 NERC Industry Webinar,
90% of planning entities have not used the existing footnote b over a planning
horizon of 13 years. To incorporate an attachment to a footnote with a complicated
and prescriptive stakeholder process to address a few instances seems to be a least
common denominator approach to planning which is opposed to FERC’s direction.
Consistent with the approach of TPL-001-2, ERCOT recommends raising the bar on
reliability and removing the footnote from the standard.

Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted
draft added detail and specificity to the already approved approach. The use of footnotes and attachments is an acceptable
mechanism for use in Reliability Standards and both mechanisms have been used before. No change made.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Southern Company

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Footnote b contains no technical basis for allowing load dropping. It is completely
based on an administrative procedure. This is not responsive to paragraphs 17 and
32 of the FERC remand order. A technical basis has to be proposed. The
"temporarily radial" concept that was proposed in earlier drafts will address this
problem. It will give a technical basis for when load dropping would be allowed. If a
technical basis is developed like FERC requires, then there is no need for a
51

Organization

Yes or No

Question 4 Comment
stakeholder process. The stakeholder process is not a bright line criteria which can
be enforced; it will change depending on the make-up of stakeholders and
therefore create inconsistencies across the grid. This approach should never be
used in a reliability standard. NERC adopted the ANSI standard process as the bench
mark in developing its reliability standards. ANSI does not use stakeholder
processes. We propose that the stakeholder process be eliminated. Create a
technical basis for when load dropping can be utilized. Keep the 75 MW maximum
amount of load that can be dropped.

Response: The SDT believes that the proposed approach is responsive to the Remand Order since it contains quantitative criteria and
a more well-defined stakeholder process. The temporary radial concept was discussed by the SDT but abandoned due to industry
comments that pointed to the difficulties in adopting this concept on a continent-wide basis. The attachment is enforceable as a clear
set of expectations has been described. The conclusions reached as a result of following the stakeholder process may be different
due to local configurations, constraints, and expectations of applicable regulatory bodies. No change made.
WAPA-RMR

Yes

I believe that the 75 MW limit is abetrary and could be too low given particular
circumstances, like the maginitude of recent load growth in the area, regulatory
hurdles in building new transmission, etc.
I also believe that the Attachment 1 stakeholder process is not needed, since it is
already covered by the FERC Ordered 890 planning process.

Western Area Power
Administration - Transmission
Owner

Yes

Western believes that the 75 MW limit is arbitrary and could be to low given
particular circumstances, like the magnitude of recent load growth in the area,
regulatory hurdles in building new transmission, etc.
We also believe that the Attachment 1 stakeholder process is not needed, since it is
already covered by the FERC Order 890 process.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The SDT used the Board of
Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it contained a stakeholder
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

52

Organization

Yes or No

Question 4 Comment

process, but because the process was not well defined, did not include quantitative and qualitative criteria for allowing curtailment
of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail and specificity to the
already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in Reliability Standards and
both mechanisms have been used before. No change made.
The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to allow an
entity to use an existing process as long as it meets the requirements shown in Attachment 1. No change made.
Entergy Services, Inc.
(Transmission)

Yes

If Attachment 1 must remain, Entergy would support the SERC PSS suggestion to
limit the application of Attachment 1 (the stakeholder process) to only those
situations where the non-consequential load at risk is above 25MW.

Response: As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The
current proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to
be supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Manitoba Hydro

Yes

Manitoba Hydro cannot support the Footnote B attachment which imposes a
stakeholder process not required in Manitoba.

Response: The open and transparent stakeholder process is a new requirement for all entities in response to the need to clarify
footnote ‘b’. No change made.
seattle city light

Yes

SCL abstains from voting on the revisions to footnote "b" in TPL-002-1c and the
corresponding footnote 12 of TPL-001-2. SCL is concerned that the revised
language oversteps the bounds of the "reliability standard" definition under Section
215 of the Federal power Act and into customer service issues that are better
served by, and under the jurisdiction of, state and local utility boards and
commissions (for details on SCL's concerns please see the comments submitted
during the initial ballot). However, in the spirit of moving this process forward,
SCL will not vote against the revised footnotes.

Public Utility District No.1 of

Yes

The Public Utility District No.1 of Snohomish County will abstain from voting on the

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

53

Organization

Yes or No

Question 4 Comment

Snohomish County

revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL001-2. The Public Utility District No.1 of Snohomish County is concerned that the
revised language oversteps the bounds of the "reliability standard" definition under
Section 215 of the Federal power Act and into customer service issues that are
better served by, and under the jurisdiction of, state and local utility boards and
commissions (for details on the Public Utility District No.1 of Snohomish County's
concerns please see the comments submitted during the initial ballot). However, in
the spirit of moving this process forward, the Public Utility District No.1 of
Snohomish County will not vote against the revised footnotes.

ISO New England Inc

In summary, this standard as proposed has misplaced jurisdictional authority under
Section 215 of the Federal Power Act. The removal of references to State and Local
authorities in the standard is required.

National Grid

Yes

We are accepting the standard as written because our current practices are better
then the prescribed maximum limit. However, we believe the appropriate limit
should be determined on a case by case basis with the state regulator input. This
standard as written, does give us the flexibility to do this.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
New Brunswick System
Operator

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We do not agree with setting a MW limit for non-consequential load loss. The
allowable amount should be determined and approved by the jurisdiction of the
area(s) whose load is affected. The intent of the TPL standard and this footnote is to
ensure that if non-sequential load loss is accounted for or relied up to ensure BES
reliability (as assessed in the planning horizon), that such a decision needs to be

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Yes or No

Question 4 Comment
approved by the appropriate jurisdiction

Response: Please see the changes shown in Q1 to account for jurisdictional differences for non-US registered entities.
MRO NSRF

Yes

Some entities remain concerned over a potential conflict and mismatch of impacts
introduced by Section III and the inclusion of non-regulated stakeholders versus
NERC regulated entities. There was not a FERC directive to include section III.
Section III overreaches the intent of the FERC order and the SAR to meet the FERC
directive. The drafting team should show the specific FERC requirement and words
in Order 693 that requires non-NERC regulatory reviews. The drafting team
technically responded to a request that Section III be removed, but avoided the the
fundamental issue. The fact that some existing non-NERC regulatory bodies may
already have a consistent practice is not a reason to include non-NERC entities into
a NERC framework. This creates a fundamental mismatch between NERC regulated
entities that must follow NERC standards and stakeholders that are not compelled
by NERC requirements. If Section III is not deleted, it is recommended that wording
be added to allow the existing FERC Order 890 stakeholder meeting process be used
to meet Attachment 1. Regulators attend these meetings and all stakeholders
(including regulators) could be asked for their objections. If there was no response
or a “lack of dissent”, this would be documented as meeting Attachment 1 to allow
the use of footnote “b” without additional special procedures.

Response: The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to
allow an entity to use an existing process as long as it meets the criteria shown in Attachment 1. No change made.
Iberdrola USA

Yes

The reasons for the “negative” vote are enumerated in our prior comments. In
summary: 1. Attachment 1 is cumbersome and inappropriate, and should be
stricken entirely.
2. All non-consequential load loss for all single-element contingencies should be
temporary, with an action plan to avoid such load loss in the future.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

55

Organization

Yes or No

Question 4 Comment
3. All actions following single-element contingencies should be an attempt to
restore lost customer service, not interrupt more customers.

Response: The transparency provided by the stakeholder process will meet the regulatory guidance provided on this issue. The
limited use of footnote ‘b’ as shown by the data collected in response to the Section 1600 data request indicates relatively few
instances where footnote ‘b’ would be used. For this reason, the SDT believes that the proposed approach strikes the right balance. .
No change made.
The SDT agrees that this is often the normal course of action. However, the SDT has not mandated this course of action since there
could be circumstances that may arise where the continued use of footnote ‘b’ may be the best over-all solution for all concerned.
No change made.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light

Under section II items 3 and 4 the wording (frequency and duration) seems to
implicate that the planners will be determining these events in a probabilistic
manor. If the probability of these events is anything other than 0 planners will have
to accommodate for those events in their planning assessments regardless of how
small the probability is for that event.

Response: The SDT does not agree that the wording requires a probabilistic determination. The planning method utilized to make the
determination is left up to the planner however this information is necessary to allow stakeholders to understand the usage of
footnote ‘b’. No change made.
ITC

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

While ITC is voting yes for this “successive ballot”, we are doing so in the interest of
ensuring that TPL 001-2 becomes fully effective as soon as possible. TPL001-2 is a
major improvement to previous standards and insuring it becomes fully effective is
important to ITC and the industry. However, we have concerns that we would like
to be noted. Because footnote B has been highlighted and expanded, there is the
possibility of future “unintended consequences”. It is highly likely that interveners

56

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Question 4 Comment
or others may attempt to stop or slow down needed corrective action plans, that do
not rely on load shedding, by suggesting that planners use this stakeholder process
before proposing projects. We suggest both NERC and FERC be prepared to deal
with these unintended consequences. We also concur in entirety with the
comments MISO is proposing to make for this project. They are consistent with past
comments ITC has made and do discuss in some detail the potential “unintended
consequences” this detailed footnote may cause.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.
Xcel Energy

Yes

While we are not satisfied with the responses to our previous comments, we have
chosen to not reiterate them here. Instead, we feel that the need to continue with
any modification to Footnote b seems moot considering FERC's recent approval of
the revised BES definition. Specifically, we believe exclusions E1 and E3, regarding
radial systems and local networks, resolves FERC's original directive on ambiguity
with footnote b. We recommend the team consider abandoning this project, and
request that NERC staff request relief from FERC on the related directives, as they
have been overcome by the modified BES definition.

Response: The SDT believes that there may be portions of the BES, even with the proposed revised BES definition, where it may still
be appropriate to address performance issues using footnote ‘b’ for Non-Consequential Load Loss. No change made.
Independent Electricity System
Operator

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) The IESO reiterate its support for allowing load interruption for a single
contingency with sufficient review/oversight and under acceptable conditions,
including no widespread adverse impact on the reliability of the interconnected
bulk power system. The reliability aspects (BES performance requirements) should
be reviewed for acceptability by the adjacent Planning Coordinators and
Transmission Planners. However, issues pertaining to economics or externalities
which may not be directly reliability-related are always available for review and

57

Organization

Yes or No

Question 4 Comment
debate by the stakeholders via the regulatory processes and subject to approval by
the regulatory authority of each jurisdiction (including those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2
approved by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5
categories to allow the application of footnote ‘b’/’12’ that is allowed for the P1
events. Events in P2, P4, and P5 can involve more elements and can be more
onerous and stressful to the system than the P1 events, and if use of footnote
‘b’/’12’ is permitted in the less stressful P1 events, it should also be permitted in P2,
P4 and P5 events. There continues to be confusion as to this inconsistency, and to
how this is to be applied (as discussed at the last webinar).
(3) We suggest that NERC Standards and their requirements should focus on what is
the anticipated outcome rather than how to achieve it. Accordingly, we believe that
the focus of footnote ‘b’, and footnote 12 should be that interruption of load must
not have a widespread, adverse impact on the reliability of the interconnected bulk
power system. A continent-wide standard should not concern itself with the
reliability of supply or supply continuity for local load, as that is the responsibility of
the applicable regulatory authority or its agencies responsible for local transmission
and retail service over the load to be curtailed. As mentioned above, NERC
Standards and their requirements should focus on what is the anticipated outcome
rather than how to achieve it. In this regard, we believe that Attachment 1 is not
necessary because it prescribes a process which goes beyond the outcome of the
standard and dictates how stakeholdering must be carried out. The individual
jurisdiction should establish the process for ensuring compliance with the standard
and decide to what extent a stakeholdering process is necessary to establish the
acceptable level of load rejection for the area in a manner consistent with local
transmission established service levels.
(4) The process presented in Section I is overly prescriptive. If a section that
prescribes the principles of a stakeholder process is required, then for Canadian
entities this section should simply state that any threshold should be established in

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

58

Organization

Yes or No

Question 4 Comment
a manner consistent with other service levels that apply to local transmission and
retail service for the load to be curtailed, as described in Q1 and for the reasons
stated therein.
Corrective action plans can rarely be implemented in a one-year time frame, and in
some cases, limited use of Non-consequential Load Loss will be preferable to
unaffordable transmission enhancements, therefore we believe that the use of
footnote ‘b’/’12’ should not be limited to the Near-Term Transmission Planning
Horizon. We propose that the phrase “the Near-Term Transmission Planning
Horizon of” be deleted from the opening paragraph.

Response: The SDT believes that it is the responsibility of the ERO to assess Adverse Reliability Impacts and is not an appropriate role
for adjacent planners. The proposed stakeholder process allows all stakeholders, including regulators, will have the necessary
information required for the indicated reviews. No change made.
Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. As shown by
this approval, the SDT and the industry disagree that there is a technical irregularity in Table 1. The Board of Trustees has also
previously approved this proposed standard. Discussions on the applicability of footnote 12 in that standard were held during
Project 2006-02 and are not part of this proceeding. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. In addition, please see the changes shown in Q1 to address
jurisdictional concerns for non-US registered entities. No change made.
Please see the changes shown in Q1 to address jurisdictional concerns for non-US registered entities.
The use of the footnote is not limited to the Near-Term Transmission Planning Horizon since the main body of the footnote states
that the footnote may be utilized “… throughput the planning horizon…”. No change made.
SERC EC Planning Standards
Subcommittee

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We continue to recommend that up to 25 MW of planned interruption be allowed
without triggering the need for a stakeholder process. We believe that this
simplification would be less burdensome and would enhance industry acceptance of
the revision, while still meeting regulatory guidance. The comments expressed
59

Organization

Yes or No

Question 4 Comment
herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board, or its officers.

TVA Transmission Reliability
Engineering and Controls

We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. We believe that this simplification
would be less burdensome and would enhance industry acceptance of the revision,
while still meeting regulatory guidance.

Response: As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The
current proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to
be supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Tacoma Power

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

While Tacoma Power appreciates NERC's attempt to address both footnotes with
the same drafting team, Tacoma Power is voting negative on the revisions to
footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL-001-2.
However, Tacoma Power would vote affirmative if a re-circulation ballot was limited
strictly to footnote "b" in TPL-002-1c. TPL-001-2 considered new types of outages
not considered by TPL version 1, such as P2-1. Although TPL-001-2 was approved by
the industry, the proposed modifications to footnote 12 in TPL-001-2 are
significantly more onerous than footnote 12 in TPL-001-2. Furthermore, since TPL001-2 is not yet enforceable, some Transmission Planners still do not realize that
automatic relay actions are considered Non Consequential Load Loss. In addition,
Tacoma Power identified over 100 MW of load in multiple locations that would be
shed in accordance with footnote 12 in TPL-001-2. Unfortunately, the structure of
the Section 1600 data request did not allow for the submittal of footnote 12 related
data. Since it is clear that the potential impact of the footnote 12 revision has not
been addressed due to the compressed timeline, Tacoma Power believes that by
separating the two standards, NERC can meet the FERC mandated deadline for
footnote b while still continuing the drafting process to achieve true industry
consensus on footnote 12. Please note that FERC orders 693 and 762 require
60

Organization

Yes or No

Question 4 Comment
addressing only footnote "b" by the using the Expedited Standards Development
Process. Earlier FERC orders discuss "single contingencies" as type Category B in
TPL-002-1; FERC has not addressed Non Consequential Load Shedding for the lower
probability "single contingencies" (i.e. P2-1) in TPL-001-2. Approving the revisions to
footnote 12 would result in negligible reliability gains at an unreasonable cost for
customers on the fringes of the power system, without affording local jurisdictional
cost benefit analysis.
Tacoma Power is also concerned that the revised language oversteps the bounds of
the "reliability standard" definition under Section 215 of the Federal Power Act.
These revisions tread on customer service issues that are better served by, and
under the jurisdiction of, state and local utility boards and commissions. For details
on Tacoma Power's concerns please see the comments submitted during the initial
ballot. However, in the spirit of moving this process forward, Tacoma Power would
vote to approve the revisions to solely TPL-002-1c if balloted separately from TPL001-2.Tacoma Power appreciates the opportunity to provide comments, and thanks
you for consideration of our comments.

Response: Any information gleaned from a Section 1600 data request based on application of footnote 12 would have been
speculative prior to the implementation of the new TPL-001-2. From the review of the comments submitted, it does not appear that
separation of the standards would be a consensus view. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
END OF REPORT

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

61

Exhibit I
Comprehensive Development Record

Project 2010-11
TPL Table 1 Order
Related Files
Status:
Adopted by the NERC Board of Trustees on February 7, 2013 and pending regulatory
approval.

Purpose/Industry Need:
The SAR is to address FERC Order RM06-16-009 which required the ERO to clarify TPL-0020, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system by June 30, 2010. The
SAR provides a revision to TPL Table 1 footnote ‘b’ to provide clarity to industry with regard
to the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system. The referenced table appears in TPL-001, TPL-002, TPL003, and TPL-004 so while the FERC Order was for TPL-002, the change is reflected in all 4
standards.

Draft

Action

Dates

Results

TPL-001-3 (formerly TPL-0012a)
Clean (111)| Redline to Last
Posting (112)
Implementation Plan
Clean (113)| Redline to Last
Posting (114)

TPL-002-2b (formerly TPL-0021c)
Clean (115)| Redline to Last
Posting (116)

Recirculation
Ballot
Info (119)

01/22/13 01/31/13
(closed)

Summary (120)
Ballot Results
(121)

Vote>>

Implementation Plan
Clean (117)| Redline to Last
Posting (118)
Draft 8
TPL-001-2a
Clean (97) | Redline to Last
Posting (98)

Successive Ballot
Updated Info
(104)

01/02/13 01/11/13
(closed)

Summary (107)
Ballot Results
(108)

Consideration of
Comments

Implementation Plan (99)

Info (105)

Draft 7
TPL-002-1c
Clean (100)| Redline to Last
Posting (101)

Vote>>

Implementation Plan (102)
Supporting Materials:
Unofficial Comment Form
(Word) (103)
Draft 7
TPL-001-2a
Clean (81)| Redline to Last
Posting (82)
Implementation Plan (83)
Draft 6
TPL-002-1c
Clean (84)| Redline to Last
Posting (85)
Implementation Plan (86)
Supporting Materials:
Unofficial Comment Form
(Word) (87)
Data Request Summary (88)

Formal
Comment Period
Info (106)

12/10/12 01/11/13
(closed)

Comments
Received (109)

Consideration of
Comments (110)

Submit
Comments>>
Initial Ballot
Updated Info
(90)
Info (91)

11/09/12 11/19/12
(closed)

Updated
Summary (93)
Full Record (94)

Vote>>
Formal
Comment Period
Info (92)

10/05/12 11/19/12
(closed)

Comments
Received (95)

Consideration of
Comments (96)

Comments
Received (79)

Consideration of
Comments (80)

Submit
Comments>>

Join Ballot
Pool>>

FERC Order 762 (89)

Draft 1

Comment Period

TPL-001-3

Info (78)

Clean (71)| Redline to Last
Approved (72)

Submit
Comments>>

10/05/12 11/05/12
(closed)

07/31/12 08/29/12
(closed)

TPL-002-1
Clean (73)| Redline to Last
Approved (74)
Supporting Materials:
Unofficial Comment Form
(Word) (75)
SAR (76)
FERC Order 762 (77)

On April 19, 2012 FERC issued Order 762 remanding TPL-002-2b and FERC proposed to remand TPL001-2. NERC has been directed to revise footnote 'b' in accordance with the directives of Order Nos.
762 and 693.

Implementation Plan (55)
TPL-001-1
Clean (56)| Redline to last
posting (57)
Redline to last approval (58)
TPL-002-1b

Recirculation
Ballot

Clean (59)| Redline to last
posting (60)
Redline to last approval (61)

Info (68)

TPL-003-1a

Vote>>

Clean (62)| Redline to last
posting (63)
Redline to last approval (64)
TPL-004-1
Clean (65)| Redline to last

01/26/11 – Summary (69)
02/05/11
(closed)
Full Record (70)

posting (66)
Redline to last approval (67)
Initial Ballot
Implementation Plan (33)

Info (47)

TPL-001-1

Vote>>

Clean (34) | Redline to last
posting (35)

Ballot Pool
Info (48)

12/27/10 - Summary (50)
01/05/11
(closed)
Full Record (51)

Consideration of
Comments (53)

11/19/10 12/22/10
(closed)

Redline to last approval (36)
TPL-002-1b
Clean (37)| Redline to last
posting (38)
Redline to last approval (39)
TPL-003-1a
Clean (40) | Redline to last
posting (41)

Comment Period

Redline to last approval (42)

Info (49)

TPL-004-1

Submit
Comments>>

11/19/10 01/05/11
(closed)

Comments
Received (52)

Consideration of
Comments (54)

Comments
Received (31)

Comment Report
(32)

Clean (43)| Redline to last
posting (44)
Redline to last approval (45)

Supporting Materials:
Comment Form (Word) (46)

Implementation Plan (20)
TPL-001-1
Clean (21) | Redline to last

Comment Period 09/08/10 10/08/10
(closed)
Submit

posting (22)

Comments>> |
Info (30)

tTPLTPL-002-1b
Clean (23)| Redline to last
posting (24)
TTPL-003-1a
Clean (25)| Redline to last
posting (26)
TPL-004-1
Clean (27)| Redline to last
posting (28)
Supporting Materials:
Comment Form (Word) (29)
SAR (1)

Initial Ballot

Implementation Plan (2)

Vote>>| Info
(12)

TPL-001-1
Clean (3)| Redline to last
approval (4)
TPL-002-1b
Clean (5) | Redline to last
approval (6)
TPL-003-1a
Clean (7) | Redline to last
approval (8)
TPL-004-1
Clean (9)| Redline to last
approval (10)
Supporting Materials:
Comment Form (Word) (11)

Pre-ballot
Review
Join>> | Info (13)

05/17/10 - Summary (15)
05/27/10
(closed)
Full Record (16)
04/15/10 05/17/10
(closed)

Comment
Report (19)

Comment Period
Submit
Comments>> |
Info (14)

Comment Report
(18)

04/15/10 05/26/10
(closed)

Comments
Received (17)

Standard Authorization Request Form
Title of Proposed Standard

2010-11 TPL Table 1 Order

Request Date

April 9, 2010

Approved by SC for Posting April 14, 2010

SAR Requester Information
Name

SAR Type (Check a box for each one
that applies.)

John Odom

Primary Contact

New Standard

FRCC

X

Revision to existing Standard

1408 N. Westshore Blvd., Suite 1002
Tampa, FL 33607
Telephone

1.813.207.7985

Fax

1.813.289.5646

E-mail

[email protected]

Withdrawal of existing Standard
Urgent Action

Purpose (Describe what the standard action will achieve in support of bulk power system
reliability.)
Provide clarity to industry on TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or
controlled interruption of electric supply where a single contingency occurs on a
transmission system.
Industry Need (Provide a justification for the development or revision of the standard,
including an assessment of the reliability and market interface impacts of implementing or
not implementing the standard action.)
The SAR is to address FERC Order RM06-16-009 which required the ERO to clarify TPL-0020, Table 1 - footnote ‘b’, regarding the planned or controlled interruption of electric supply
where a single contingency occurs on a transmission system by June 30, 2010.
Brief Description (Provide a paragraph that describes the scope of this standard action.)
The SAR provides a revision to TPL Table 1 footnote ‘b’ to provide clarity to industry with
regard to the planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system. The referenced table appears in TPL-001,
TPL-002, TPL-003, and TPL-004 so while the FERC Order was for TPL-002, the change is
reflected in all 4 standards.
Detailed Description (Provide a description of the proposed project with sufficient details
for the standard drafting team to execute the SAR.)
The ATFNSDT (Project 2006-02) has developed a clarification to TPL Table 1 – footnote ‘b’
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Authorization Request

concerning the loss of load and handling of firm transfers when a single contingency occurs
on the transmission system.
With regard to the load shedding issue, the SDT is proposing the following revision to
footnote ‘b’:
No interruption of firm Load is allowed except: (1) Interruption of Load that is directly
served by the elements that are removed from service as a result of the Contingency, or (2)
Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted
to meet performance requirements only on those now radial Transmission Facilities.
On the firm transfer issue, the SDT developed the following clarification:
No curtailment of Firm Transmission Service is allowed except when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated
that Facilities remain within applicable Facility Ratings and those adjustments do not result
in the shedding of any firm Load. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.
Since this clarification may present a different interpretation of footnote ‘b’ than the one
presently used by some entities, the SDT is proposing a 60 month implementation plan to
allow those entities time to react.

SAR–2

Standards Authorization Request

Reliability Functions
The Standard will Apply to the Following Functions (Check box for each one that applies.)

X

X

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within a Planning Coordinator area.

Transmission
Planner

Develops a >one year plan for the reliability of the interconnected
Bulk Electric System within its portion of the Planning Coordinator
area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Transmission
Owner

Owns and maintains transmission facilities.

Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

Market
Operator

Interface point for reliability functions with commercial functions.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–3

Standards Authorization Request

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
x

1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–4

Standards Authorization Request

Related Standards
Standard No.

Explanation

TPL-001-0.1

System Performance Under Normal (No Contingency) Conditions (Category
A)

TPL-002-0b

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

TPL-003-0a

System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

TPL-004-0

System Performance Following Extreme Events Resulting in the Loss of
Two or More Bulk Electric System Elements (Category D)

Related SARs
SAR ID

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR–5

Implementation Plan for Project 2010-11: TPL Table 1 Order
Standards Involved:
•

TPL-001-1 — System Performance Under Normal (No Contingency) Conditions (Category
A)

•

TPL-002-1b — System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

•

TPL-003-1 — System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

•

TPL-004-1 — System Performance Following Extreme Events Resulting in the Loss of Two
or More Bulk Electric System Elements (Category D)

Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards and no proposed changes to other
standards.
Compliance with Standards
The four standards are all applicable to both the Transmission Planner and the Planning
Authority.
Effective Dates
The effective date is the date entities are expected to meet the performance identified in these
standards.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions where no
regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.
All other requirements remain in effect per previous approvals.

116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standard TPL-001-1 — System Performance Under Normal Conditions

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Effective Date: TBD

Page 1 of 6

Standard TPL-001-1 — System Performance Under Normal Conditions

A.

Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

B.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.
Requirements

R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

Effective Date: TBD

Page 2 of 6

Standard TPL-001-1 — System Performance Under Normal Conditions

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C.

Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.

Effective Date: TBD

Page 3 of 6

Standard TPL-001-1 — System Performance Under Normal Conditions

D.

Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E.

Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

Effective Date: TBD

Page 4 of 6

Standard TPL-001-1 — System Performance Under Normal Conditions
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

Effective Date: TBD

Page 5 of 6

Standard TPL-001-1 — System Performance Under Normal Conditions

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements
that are removed from service as a result of the Contingency, or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where that Load
must be interrupted to meet performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable
Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions should also be
respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBD

Page 6 of 6

Standard TPL-001-01.1 — System Performance Under Normal Conditions

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page 1 o

Standard TPL-001-01.1 — System Performance Under Normal Conditions

A.

Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-01.1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

B.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effectiveMay 13,
2009.
Requirements

R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page 2 o

Standard TPL-001-01.1 — System Performance Under Normal Conditions

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-01_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C.

Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-01_R1 and TPL-001-01_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-01_R3.

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page 3 o

Standard TPL-001-01.1 — System Performance Under Normal Conditions

D.

Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E.

Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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.

TBD

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

Revised

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page 4 o

Standard TPL-001-01.1 — System Performance Under Normal Conditions
Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page

Standard TPL-001-01.1 — System Performance Under Normal Conditions

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers. No interruption of firm Load is allowed except: (1) Interruption of Load
that is directly served by the elements that are removed from service as a result of the Contingency, or (2)
Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a
result of the Contingency and where that Load must be interrupted to meet performance requirements only on
those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable
Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions should also be
respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page

Standard TPL-001-01.1 — System Performance Under Normal Conditions
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: October 29, 200Effective Date: May 13, 2009TBD

Page

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Effective Date: TBD

Page 1 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective .

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Effective Date: TBD

Page 2 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

Effective Date: TBD

Page 3 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Effective Date: TBD

Page 4 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Effective Date: TBD

Page 5 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are
removed from service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to
meet performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBD

Page 6 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Effective Date: TBD

Page 7 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Effective Date: TBD

Page 8 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element
Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Effective Date: TBD

Page 9 of 11

Standard TPL-002-1b — System Performance Following Loss of a Single BES Element

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

Effective Date: TBD

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Standard TPL-002-1b — System Performance Following Loss of a Single BES Element

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Effective Date: TBD

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Standard TPL-002-0b 1b — System Performance Following Loss of a Single BES Element

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Adopted by NERC Board of Trustees: November 5, 2009Effective Date: TBD

Page 1 o

Standard TPL-002-0b 1b — System Performance Following Loss of a Single BES Element
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-0b1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effectiveImmediately after approval of applicable regulatory authorities. .

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Adopted by NERC Board of Trustees: November 5, 2009Effective Date: TBD

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Standard TPL-002-0b 1b — System Performance Following Loss of a Single BES Element
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-01_R1 and TPL-002-01_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-01_R3.
D. Compliance

Adopted by NERC Board of Trustees: November 5, 2009Effective Date: TBD

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Standard TPL-002-0b 1b — System Performance Following Loss of a Single BES Element
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

0c1b

Adopted by NERC Board of Trustees: November 5, 2009Effective Date: TBD

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Standard TPL-002-0b 1b — System Performance Following Loss of a Single BES Element
Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: November 5, 2009Effective Date: TBD

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Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e



3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers. No interruption
of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission
Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to meet
performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 6 of 11

Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 7 of 11

Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 8 of 11

Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element
Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 9 of 11

Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 10 of 11

Standard TPL-002-0a 1b — System Performance Following Loss of a Single BES Element

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Effective Date: TBD

Adopted by NERC Board of Trustees: February 8, 2005Page 11 of 11

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Effective Date: TBD

Page 1 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective .

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

Effective Date: TBD

Page 2 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

Effective Date: TBD

Page 3 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Effective Date: TBD

Page 4 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Effective Date: TBD

Page 5 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are
removed from service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to
meet performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBD

Page 6 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Effective Date: TBD

Page 7 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Effective Date: TBD

Page 8 of 9

Standard TPL-003-1a — System Performance Following Loss of Two or More BES Elements

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Effective Date: TBD

Page 9 of 9

Standard TPL-003-0a1a — System Performance Following Loss of Two or More BES Elements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Adopted by NERC Board of Trustees: February 8, 2005Effective Date: April 1, 2005TBD

Page 1 o

Standard TPL-003-0a1a — System Performance Following Loss of Two or More BES Elements

A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-0a1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effectiveApril 1, 2005 .

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

Adopted by NERC Board of Trustees: February 8, 2005Effective Date: April 1, 2005TBD

Page 2 o

Standard TPL-003-0a1a — System Performance Following Loss of Two or More BES Elements

R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-01_R1 and TPL-003-01_R2.

Adopted by NERC Board of Trustees: February 8, 2005Effective Date: April 1, 2005TBD

Page 3 o

Standard TPL-003-0a1a — System Performance Following Loss of Two or More BES Elements

M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

April 2010TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

0b1a

Adopted by NERC Board of Trustees: February 8, 2005Effective Date: April 1, 2005TBD

Page 4 o

Standard TPL-003-0a1a — System Performance Following Loss of Two or More BES Elements

Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005Effective Date: April 1, 2005TBD

Page 5 o

Standard TPL-003-0a 1a — System Performance Following Loss of Two or More BES Elements

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers. No interruption
of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission
Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to meet
performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 200Effective Date: April 1, 2005TBD

Page 6 o

Standard TPL-003-0a 1a — System Performance Following Loss of Two or More BES Elements

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Adopted by NERC Board of Trustees: February 8, 200Effective Date: April 1, 2005TBD

Page 7 o

Standard TPL-003-0a 1a — System Performance Following Loss of Two or More BES Elements

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Adopted by NERC Board of Trustees: February 8, 200Effective Date: April 1, 2005TBD

Page 8 o

Standard TPL-003-0a 1a — System Performance Following Loss of Two or More BES Elements

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Adopted by NERC Board of Trustees: February 8, 200Effective Date: April 1, 2005TBD

Page 9 o

Standard TPL-004-1 — System Performance Following Extreme BES Events

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Effective Date: TBD

1 of 6

Standard TPL-004-1 — System Performance Following Extreme BES Events
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

Effective Date: TBD

2 of 6

Standard TPL-004-1 — System Performance Following Extreme BES Events
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

Effective Date: TBD

3 of 6

Standard TPL-004-1 — System Performance Following Extreme BES Events

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Effective Date: TBD

4 of 6

Standard TPL-004-1 — System Performance Following Extreme BES Events
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Effective Date: TBD

5 of 6

Standard TPL-004-0a — System Performance Following Extreme BES Events

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are
removed from service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to
meet performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBD

6 of 6

Standard TPL-004-0 1 — System Performance Following Extreme BES Events

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. None.
Proposed Action Plan and Description of Current Draft:
The SDT has submitted a SAR to address FERC Order RM06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of
electric supply where a single Contingency occurs on a Transmission System by June 30, 2010.
Due to the timeframe involved, the SDT has requested an Urgent Action process be approved by
the Standards Committee. To accommodate this process, the SDT has supplied drafts of the
affected TPL standards as part of the SAR submittal.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Submit SAR to SC

April 2010

2. Approval of SAR by SC

April 2010

3. 30 day pre-ballot period

April – May 2010

4. Initial ballot

May 2010

5. Recirculation ballot

June 2010

6. Submit to BOT for approval

June 2010

7. File with FERC

June 2010

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20051 of

Standard TPL-004-0 1 — System Performance Following Extreme BES Events
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-0a 1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effectiveApril 1, 2005

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20052 of

Standard TPL-004-0 1 — System Performance Following Extreme BES Events
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-01_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-01_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20053 of

Standard TPL-004-0 1 — System Performance Following Extreme BES Events

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20054 of

Standard TPL-004-0 1 — System Performance Following Extreme BES Events
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section

Yes

2. Breaker (failure or internal Fault)

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20055 of

Standard TPL-004-0a — System Performance Following Extreme BES Events

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers. No interruption
of firm Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission
Facilities made temporarily radial as a result of the Contingency and where that Load must be interrupted to meet
performance requirements only on those now radial Transmission Facilities.
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: April 1, 2005TBD
6

Adopted by NERC Board of Trustees: February 8, 20056 of

Unofficial Comment Form for SAR for Project 2010-11: TPL Table 1 Order
Please DO NOT use this form to submit comments. Please the electronic form located at
the link below to submit comments on the SAR for Project 2010-11: TPL Table 1 Order.
This comment form must be completed by May 25, 2010.
If you have questions please contact Ed Dobrowolski at [email protected] or by
telephone at 609-947-3673.
Background Information
The SAR is to address FERC Order RM06-16-009 which required the ERO to clarify TPL-0020, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply
where a single contingency occurs on a transmission system by June 30, 2010.
The SAR provides a revision to TPL Table 1 footnote ‘b’ to provide clarity to industry with
regard to the planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system. The referenced table appears in TPL-001,
TPL-002, TPL-003, and TPL-004 so while the FERC Order was for TPL-002, the change is
reflected in all 4 standards.
1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC
Order RM-06-16-009 which required the ERO to clarify TPL-002-0, Table 1 — footnote
‘b’, regarding the planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system by June 30, 2010. Do you agree with the
proposed changes and if not, please provide specific reasons for your disagreement.
Yes
No
Comments:
2. Are you aware of any conflicts caused by compliance with the proposed language in
Table 1 — footnote b and any regulatory function, rule order, tariff, rate schedule,
legislative requirement or agreement? If yes, please identify the conflict.
Yes
No
Comments:

116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Initial Ballot Window Open
May 17–27, 2010
Now available at: https://standards.nerc.net/CurrentBallots.aspx
TPL Table 1, Footnote B (Project 2010-11) 
An initial ballot window for the TPL Table 1, Footnote B changes is now open until 8 p.m. EST on May 27, 2010.
The ballot includes four draft standards and an implementation plan. The only change proposed in each of the four
standards (TPL-001-1, TPL-002-1b, TPL-003-1a, and TPL-004-1) is to Table 1, Footnote ‘b’.
 
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following page:
https://standards.nerc.net/CurrentBallots.aspx
Next Steps
Voting results will be posted and announced after the ballot window closes.
Project Background
The Assess Transmission Future Needs Standard Drafting Team (Project 2006-02) has developed a clarification to TPL
Table 1 — footnote ‘b’ concerning the loss of load and handling of firm transfers when a single contingency occurs on the
transmission system.
The drafting team is proposing the following revision to footnote ‘b’: No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service as a result of the Contingency,
or (2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.
On the firm transfer issue, the drafting team developed the following clarification:
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustments do not result in the shedding of any firm Load. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions should also be respected.
Since this clarification may present a different interpretation of footnote ‘b’ than the one presently used by some entities,
the SDT is proposing a 60 month implementation plan to allow those entities time to react
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance,
please contact Lauren Koller at [email protected]

Standards Announcement

Standards Authorization Request (SAR)
Ballot Pool and Pre-ballot Window (with Comment Period)
Project 2010-11: TPL Table 1, Footnote B
Now available at: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
TPL Table 1, Footnote B SAR (Project 2010-11)
The Standards Committee, in response to a FERC Order issued March 18, 2010, has posted a proposed
SAR, four draft standards, TPL-001-1, TPL-002-1b, TPL-003-1a, and TPL-004-1, and an implementation plan,
for a simultaneous pre-ballot review and 40-day comment period. The only change proposed in each of the four
standards is to Table 1, Footnote ‘b’.
The Order requires the ERO to file the revised standards by June 30. 2010. To meet this due date, the Standards
Committee approved the following deviation from the standards development process:
•

The proposed changes to the standards will be posted for a 40-day comment period. The Ballot Pool
will be formed during the first 30 days of the 40-day comment period;

•

The initial ballot will be conducted during the last 10 days of the 40-day comment period; and

•

The drafting team may make modifications to the footnote between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the footnote.

Ballot Pool (through May 17, 2010)
Registered Ballot Body members may join the ballot pool to be eligible to vote on this interpretation until 8
a.m. EDT on May 17, 2010.
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: bp-2010-11_TPL_SAR_in
Comment Period (through May 25, 2010)
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at 609-524-7047.
The status, purpose, a clean and redline version of the four standards, and supporting documents for this project
— including an off-line, unofficial copy of the questions listed in the comment form — are posted at the
following site: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Project Background:
The Assess Transmission Future Needs Standard Drafting Team (Project 2006-02) has developed a clarification
to TPL Table 1 — footnote ‘b’ concerning the loss of load and handling of firm transfers when a single
contingency occurs on the transmission system.

The drafting team is proposing the following revision to footnote ‘b’: No interruption of firm Load is allowed
except: (1) Interruption of Load that is directly served by the elements that are removed from service as a result
of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet performance
requirements only on those now radial Transmission Facilities.
On the firm transfer issue, the drafting team developed the following clarification:
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable
Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions should also be
respected.
Since this clarification may present a different interpretation of footnote ‘b’ than the one presently used by some
entities, the SDT is proposing a 60 month implementation plan to allow those entities time to react.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Lauren Koller at [email protected]

Standards Announcement

Standards Authorization Request (SAR)
Ballot Pool and Pre-ballot Window (with Comment Period)
Project 2010-11: TPL Table 1, Footnote B
Now available at: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
TPL Table 1, Footnote B SAR (Project 2010-11)
The Standards Committee, in response to a FERC Order issued March 18, 2010, has posted a proposed
SAR, four draft standards, TPL-001-1, TPL-002-1b, TPL-003-1a, and TPL-004-1, and an implementation plan,
for a simultaneous pre-ballot review and 40-day comment period. The only change proposed in each of the four
standards is to Table 1, Footnote ‘b’.
The Order requires the ERO to file the revised standards by June 30. 2010. To meet this due date, the Standards
Committee approved the following deviation from the standards development process:
•

The proposed changes to the standards will be posted for a 40-day comment period. The Ballot Pool
will be formed during the first 30 days of the 40-day comment period;

•

The initial ballot will be conducted during the last 10 days of the 40-day comment period; and

•

The drafting team may make modifications to the footnote between the initial and recirculation ballots
based on stakeholder comments to improve the overall quality of the footnote.

Ballot Pool (through May 17, 2010)
Registered Ballot Body members may join the ballot pool to be eligible to vote on this interpretation until 8
a.m. EDT on May 17, 2010.
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: bp-2010-11_TPL_SAR_in
Comment Period (through May 25, 2010)
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Lauren Koller at 609-524-7047.
The status, purpose, a clean and redline version of the four standards, and supporting documents for this project
— including an off-line, unofficial copy of the questions listed in the comment form — are posted at the
following site: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Project Background:
The Assess Transmission Future Needs Standard Drafting Team (Project 2006-02) has developed a clarification
to TPL Table 1 — footnote ‘b’ concerning the loss of load and handling of firm transfers when a single
contingency occurs on the transmission system.

The drafting team is proposing the following revision to footnote ‘b’: No interruption of firm Load is allowed
except: (1) Interruption of Load that is directly served by the elements that are removed from service as a result
of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet performance
requirements only on those now radial Transmission Facilities.
On the firm transfer issue, the drafting team developed the following clarification:
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable
Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions should also be
respected.
Since this clarification may present a different interpretation of footnote ‘b’ than the one presently used by some
entities, the SDT is proposing a 60 month implementation plan to allow those entities time to react.
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance,
please contact Lauren Koller at [email protected]

Standards Announcement
Initial Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
TPL Table 1, Footnote B (Project 2010-11)
The initial ballot for TPL Table 1, Footnote B ended on May 27, 2010.
Ballot Results
Voting statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum:
Approval:

84.41 %
63.75 %

Since at least one negative ballot included a comment, these results are not final. A second (or recirculation)
ballot must be conducted. Ballot criteria are listed at the end of the announcement.
Next Steps
As part of the recirculation ballot process, the drafting team must draft and post responses to voter comments.
The drafting team will also determine whether or not to make revisions to the balloted item(s). Should the team
decide to make revisions, the revised item(s) will return to the initial ballot phase.
Project Background
The Assess Transmission Future Needs Standard Drafting Team (Project 2006-02) has developed a clarification
to TPL Table 1 — footnote ‘b’ concerning the loss of load and handling of firm transfers when a single
contingency occurs on the transmission system.
The drafting team is proposing the following revision to footnote ‘b’: No interruption of firm Load is allowed
except: (1) Interruption of Load that is directly served by the elements that are removed from service as a result
of the Contingency, or (2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet performance
requirements only on those now radial Transmission Facilities.
On the firm transfer issue, the drafting team developed the following clarification:
No curtailment of Firm Transmission Service is allowed except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable
Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions should also be
respected.
Since this clarification may present a different interpretation of footnote ‘b’ than the one presently used by some
entities, the SDT is proposing a 60 month implementation plan to allow those entities time to react

More information is available on the project page: http://www.nerc.com/filez/standards/Project201011_TPL_Table-1_Order.html
Standards Development Process
The Reliability Standards Development Procedure contains all the procedures governing the standards
development process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
Ballot Criteria
Approval requires both a (1) quorum, which is established by at least 75% of the members of the ballot pool for
submitting either an affirmative vote, a negative vote, or an abstention, and (2) A two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and nonresponses. If there are no negative votes with reasons from the
first ballot, the results of the first ballot shall stand. If, however, one or more members submit negative votes
with reasons, a second ballot shall be conducted.
For more information or assistance,
please contact Lauren Koller at [email protected]

NERC Standards

 

Newsroom  •  Site Map  •  Contact NERC

  
Advanced Search

 
User Name

Ballot Results

Ballot Name: Project 2010-11 SAR for TPL Table 1 Order_in

Password

Ballot Period: 5/17/2010 - 5/27/2010
Ballot Type: Initial

Log in

Total # Votes: 222

Register
 

Total Ballot Pool: 263
Quorum: 84.41 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
63.75 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
77
10
58
13
49
36
0
7
5
8
263

#
Votes

 
1
0.7
1
1
1
1
0
0.3
0.3
0.7
7

#
Votes

Fraction
 

36
5
30
7
25
17
0
2
1
6
129

Negative
Fraction

 
0.59
0.5
0.566
0.636
0.641
0.63
0
0.2
0.1
0.6
4.463

Abstain
No
# Votes Vote

 
25
2
23
4
14
10
0
1
2
1
82

 
0.41
0.2
0.434
0.364
0.359
0.37
0
0.1
0.2
0.1
2.537

 
1
1
2
1
0
3
0
1
1
1
11

15
2
3
1
10
6
0
3
1
0
41

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
Associated Electric Cooperative, Inc.
Avista Corp.
BC Transmission Corporation
Beaches Energy Services

Member
 
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
John Bussman
Scott Kinney
Gordon Rawlings
Joseph S. Stonecipher

https://standards.nerc.net/BallotResults.aspx?BallotGUID=853de147-8f77-43bb-a027-e062fe891146[5/28/2010 9:01:32 AM]

Ballot
 
Negative
Affirmative
Affirmative
Affirmative

Negative
Affirmative

Comments
 
View

View

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Black Hills Corp
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy
Central Maine Power Company
City of Vero Beach
City Utilities of Springfield, Missouri
Commonwealth Edison Co.
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
E.ON U.S. LLC
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Idaho Power Company
ITC Transmission
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
New York Power Authority
Northeast Utilities
Northern Indiana Public Service Co.
Ohio Valley Electric Corp.
Oncor Electric Delivery
Orlando Utilities Commission
Otter Tail Power Company
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Portland General Electric Co.
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Tennessee Valley Authority
Tri-State G & T Association Inc.
Tucson Electric Power Co.

Eric Egge
Donald S. Watkins
Tony Kroskey
Paul Rocha
Brian Conroy
Randall McCamish
Jeff Knottek
Daniel Brotzman
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
Larry Monday
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch

Negative
Affirmative

View
View

Abstain
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative

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Robert Solomon
Ajay Garg
Ronald D. Schellberg
Elizabeth Howell
Michael Gammon
Stan T. Rzad
Larry E Watt
John W Delucca
Doug Bantam
Michelle Rheault
Danny Dees
Terry Harbour
Saurabh Saksena
Arnold J. Schuff
David H. Boguslawski
Kevin M Largura
Robert Mattey
Michael T. Quinn
Brad Chase
Lawrence R. Larson
Chifong L. Thomas
Mark Sampson
Ronald Schloendorn
Frank F. Afranji
Richard J Kafka
Larry D. Avery
Brenda L Truhe
Sammy Roberts
Kenneth D. Brown
Catherine Koch
Linda Brown
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
James L. Jones
Gary W Cox
Larry Akens
Keith V. Carman
John Tolo

https://standards.nerc.net/BallotResults.aspx?BallotGUID=853de147-8f77-43bb-a027-e062fe891146[5/28/2010 9:01:32 AM]

Negative
Negative

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View

Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative

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Affirmative
Affirmative
Affirmative
Affirmative
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Negative
Negative
Negative
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Affirmative
Negative
Affirmative
Negative
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Affirmative
Negative

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NERC Standards
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Westar Energy
Western Area Power Administration
Xcel Energy, Inc.
BC Transmission Corporation
California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
American Electric Power
Atlantic City Electric Company
BC Hydro and Power Authority
Blue Ridge Power Agency
Bonneville Power Administration
City of Bartow, Florida
City of Green Cove Springs
Cleco Utility Group
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Power & Light Co.
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Orlando Utilities Commission
OTP Wholesale Marketing
PacifiCorp
PECO Energy an Exelon Co.
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 2 of Grant County
Salt River Project
Santee Cooper
Seattle City Light
South Carolina Electric & Gas Co.

Allen Klassen
Brandy A Dunn
Gregory L Pieper
Faramarz Amjadi
Timothy VanBlaricom
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Raj Rana
James V. Petrella
Pat G. Harrington
Duane S. Dahlquist
Rebecca Berdahl
Matt Culverhouse
Gregg R Griffin
Bryan Y Harper
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Kevin Querry
Joe McKinney
W. R. Schoneck
Lee Schuster
Anthony L Wilson
R Scott S. Barfield-McGinnis
Sam Kokkinen
Gwen S Frazier
Michael D. Penstone
Garry Baker
Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Charles A. Freibert
Greg C Parent
Thomas C. Mielnik
Don Horsley
Marilyn Brown
Michael Schiavone
William SeDoris
Ballard Keith Mutters
Bradley Tollerson
John Apperson
Vincent J. Catania
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Greg Lange
John T. Underhill
Zack Dusenbury
Dana Wheelock
Hubert C. Young

https://standards.nerc.net/BallotResults.aspx?BallotGUID=853de147-8f77-43bb-a027-e062fe891146[5/28/2010 9:01:32 AM]

Negative
Negative
Affirmative
Affirmative
Abstain
Affirmative

Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
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Negative
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Affirmative
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Negative
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Negative

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NERC Standards
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5

Southern California Edison Co.
Tampa Electric Co.
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
City of New Smyrna Beach Utilities
Commission
Consumers Energy
Detroit Edison Company
Florida Municipal Power Agency
Georgia System Operations Corporation
Integrys Energy Group, Inc.
Modesto Irrigation District
Ohio Edison Company
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Avista Corp.
Bonneville Power Administration
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power LLC
Conectiv Energy Supply, Inc.
Consolidated Edison Co. of New York
Consumers Energy
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
New York Power Authority
Northern Indiana Public Service Co.
Orlando Utilities Commission
Otter Tail Power Company
PacifiCorp
Portland General Electric Co.
PowerSouth Energy Cooperative
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
RRI Energy
Salt River Project
Seattle City Light
Seminole Electric Cooperative, Inc.
South California Edison Company
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers Northwestern
Division
U.S. Bureau of Reclamation
Wisconsin Electric Power Co.
Wisconsin Public Service Corp.

David Schiada
Ronald L Donahey
James R. Keller
Michael Ibold

Negative

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Negative
Negative

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Timothy Beyrle

Affirmative

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David Frank Ronk
Daniel Herring
Frank Gaffney
Guy Andrews
Christopher Plante
Spencer Tacke
Douglas Hohlbaugh
Hao Li
Steven R Wallace
Steve McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Edward F. Groce
Francis J. Halpin
Alan Gale
Karl E. Kohlrus
Grant Bryant
Kara Dundas
Wilket (Jack) Ng
James B Lewis
Christy Wicke
Mike Garton
Robert Smith
Stephen Ricker
Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Cynthia E Sulzer
Donald Gilbert
Scott Heidtbrink
Mike Blough
Dennis Florom
Charlie Martin
Mark Aikens
Christopher Schneider
Gerald Mannarino
Michael K Wilkerson
Richard Kinas
Ward Uggerud
Sandra L. Shaffer
Gary L Tingley
Tim Hattaway
Mark A. Heimbach
Wayne Lewis
David Murray
Thomas J. Bradish
Glen Reeves
Michael J. Haynes
Brenda K. Atkins
Ahmad Sanati
RJames Rocha
Scott M. Helyer
George T. Ballew

Negative
Affirmative
Affirmative
Negative

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Karl Bryan
Martin Bauer P.E.
Linda Horn
Leonard Rentmeester

https://standards.nerc.net/BallotResults.aspx?BallotGUID=853de147-8f77-43bb-a027-e062fe891146[5/28/2010 9:01:32 AM]

View

Negative
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Affirmative
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NERC Standards
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10
 

Xcel Energy, Inc.
AEP Marketing
Black Hills Corp
Bonneville Power Administration
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Great River Energy
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
OTP Wholesale Marketing
Progress Energy
PSEG Energy Resources & Trade LLC
Public Utility District No. 1 of Chelan County
RRI Energy
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
JDRJC Associates
Montana Consumer Counsel
Power Energy Group LLC
Shafer, Kline, & Warren Inc. (SKW)
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
North Carolina Utilities Commission
Oregon Public Utility Commission
Electric Reliability Council of Texas, Inc.
Florida Reliability Coordinating Council
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Western Electricity Coordinating Council

Liam Noailles
Edward P. Cox
Tyson Taylor
Brenda S. Anderson
Matthew D Cripps
John Mick
Nickesha P Carrol
Brenda Powell
Louis S Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti
Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Donna Stephenson
Thomas Saitta
Paul Shipps
Eric Ruskamp
Daryn Barker
Daniel Prowse
Thomas Papadopoulos
Joseph O'Brien
David Ried
Bruce Glorvigen
James Eckelkamp
James D. Hebson
Hugh A. Owen
Trent Carlson
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Matt H Bullard
Marjorie S. Parsons

Negative
Affirmative

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Abstain
Negative
Affirmative
Abstain
Affirmative

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Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
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Negative
Affirmative
Negative
Affirmative
Negative
Abstain

John Stonebarger

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Affirmative
Negative
Negative
Negative
Affirmative

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Affirmative

David F. Lemmons
Negative
James A Maenner
Negative
Roger C Zaklukiewicz
Affirmative
Jim D. Cyrulewski
Abstain
Lawrence P Nordell
Peggy Abbadini
Michael J Bequette, P.E.
Affirmative
Terry Volkmann
William Mitchell Chamberlain Negative

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Donald E. Nelson
Diane J. Barney

Affirmative

Kimberly J. Jones
Jerome Murray
Kent Saathoff
Linda Campbell
Dan R. Schoenecker
Alan Adamson
Guy V. Zito
Jacquie Smith
Carter B Edge
Louise McCarren

Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative

 

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NERC Standards

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https://standards.nerc.net/BallotResults.aspx?BallotGUID=853de147-8f77-43bb-a027-e062fe891146[5/28/2010 9:01:32 AM]

Individual or group. (22 Responses)
Name (13 Responses)
Organization (13 Responses)
Question 1 (22 Responses)
Question 1 Comments (22 Responses)
Question 2 (22 Responses)
Question 2 Comments (22 Responses)
Group
No
The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission again
references Order 693 and specifically highlights comments by Duke Power Company and Northern Indiana Public
Service Company by saying the arguments made to date to allow non-consequential load loss after a single
contingency event is “based largely on the matter of economics, not reliability, with the underlying premise that it is not
economically feasible to invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.” The proposed changes to footnote ‘b’ indicate “No interruption of firm
Load is allowed except:… (2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet performance
requirements only on those now radial Transmission Facilities.” The exception described appears to still allow nonconsequential load loss. FERC describes in RM06-16-009 non-consequential load loss as “the removal, by any means,
of any firm load that is not directly served by the elements that are removed from service as a result of the
contingency.” In referencing Order 693, the Commission reiterated its position that TPL standards “should not allow an
entity to plan for the loss of non-consequential load in the event of a single contingency.” “Must” should be used instead
of “should” in the last sentence of the footnote, making it to read “Facility Ratings in those regions must also be
respected.”
Yes
Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities who
attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with rate recovery
authority may take the position that considering the economics of proposed investments intended to prevent nonconsequential loss of small or remote load is acceptable. This potential conflict between state and federal positions
could place utilities in a compromising position.
Individual
Robert Casey
Georgia Transmission Corporation (Bulk System Planning)
No
Georgia Transmission Corporation (GTC) believes that the requirement prohibiting loss of non-consequential load for
P1, P2.1 and P3 events is an overreach by the standard into local load quality of service issues. We believe that
FERC’s directive in (Docket No. RM06-16) to prohibit the loss of non-consequential load in the event of a single
contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power system to prevent
“instability, uncontrolled separation or cascading failures,” none of which occur when utilities implement a planned and
orderly loss of non-consequential load. Hence, the Commission’s directive to prohibit utilities from incorporating
carefully controlled loss of non-consequential load into their planning protocols appears to extend the Commission’s
reach beyond its review of measures that are needed for “reliable operation” of the bulk-power system as defined under
Section 215 of the Federal Power Act. Such directive constitutes an overreaching of the Commission’s jurisdiction
under Section 215 of the Federal Power Act into the jurisdiction of state commissions which generally have
responsibility for overseeing quality of service issues applicable to local load. While the current revised footnote b is an
improvement from the prohibition on loss of non-consequential load associated with the recently balloted version of
TPL-001-1, it still does not allow Transmission Planners to use appropriate discretion regarding loss of nonconsequential load. Transmission Planners, customers, and local regulators should jointly control the decision making
when BES reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit point of view to allow loss of
non-consequential load. We also note that on April 19 NERC filed a request for rehearing with FERC asking that the
Commission revise the directive in Paragraph 8 of the March 18 TPL-002 Order to allow NERC the necessary time to
incorporate changes to the TPL-002 Reliability Standard through the Reliability Standards Development Process that
are necessary to achieve bulk power system reliability. NERC also requested that the Commission grant NERC’s
Motion for Stay to stay the Order so that a public technical conference with opportunity for comment can be held in
order to provide parties an opportunity to meet and discuss the technical considerations of developing a modification to
the TPL-002 standard that prohibits the loss of non-consequential firm load in the event of an N-1 contingency. NERC’s
April 19 filing pointed out that if the Commission’s directive to disallow the loss of non-consequential firm load for an N-

1 contingency is implemented, a question is presented regarding whether the Reliability Standard still serves the
purpose of ensuring the Reliable Operation of the bulk power system by preventing instability, uncontrolled separation,
and cascading failures. That is, the Commission’s directive sets forth an expectation that NERC is to implement
standards that address all loss of load at costs that may not be commensurate with bulk power system reliability, as
statutorily defined, which is fundamentally different from what the Reliability Standards were intended to do.
Yes
See response to Question #1.
Group
Yes
For better clarity delete the phrase “when coupled with” in the second paragraph of footnote ‘b.’
No
The comments expressed herein represent a consensus of the views of the above named members of the SERC
Engineering Committee Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board or its officers.
Group
Yes
No
Individual
Thad Ness
American Electric Power
Yes
No
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
MH agrees with the SDT proposal.
No
Group
No
We propose that the section in double parentheses be deleted. The proposed wording by the drafting team seems to
imply that the curtailment of firm transmission service is permitted to address single contingency constraints if coupled
with the redispatch of network resources. The original language stated only that curtailments were permitted to prepare
for the next contingency, not to address loading related to the initial contingency. The proposed wording could be
interpreted to allow redispatch/firm curtailments to address any single contingency constraint. Southern Companies
recommend that the original language relating to “preparing for the next contingency” be incorporated into the drafting
team’s proposal. ((Planned or controlled interruption of electric supply to radial customers or some local Network
customers, connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for the next contingency,
system adjustments are permitted, including curtailments of contracted Firm (non-recallable reserved) electric power
Transfers.)) No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the
elements that are removed from service as a result of the Contingency, or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must
be interrupted to meet performance requirements only on those now radial Transmission Facilities. To prepare for the
next contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power transfers No curtailment of Firm Transmission Service is allowed except when coupled with
the appropriate re-dispatch of resources obligated to re-dispatch. where it can It must be demonstrated that Facilities
remain within applicable Facility Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions
should also be respected.
No
Individual

Martin Bauer
US Bureau of Reclamation
Yes
No
Group
Yes
On the firm transfer issues, the term "Firm Transmission Service" should be replaced with "Firm Transfers" to be
consistent with the fourth column of the existing Table 1 Transmission System Standards - Normal and Emergency
Conditions.
No
Individual
Kirit Shah
Ameren
Yes
We were ok with the previous language. Though we do not intend to drop non-consequential load for a single
contingency, we undersatnd that other ares may have been following such practice without degarding the relaibility of
BES. We believe that they can continue this practice if they develop non-firm contracts with these customers.
No
Group
No
For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the
customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also allowed, if the
tripping of the load is either accepted or volunteered by the customer in lieu of significant transmission system
modifications.
No
Individual
Robert W. Roddy
Dairyland Power Cooperative
No
DPC concurs with the MRO comments: For Footnote b, add a third exception to the list, "or (3) end-use load that is
either accepted or volunteered by the customer". It is a widely-held understanding that the tripping of nonconsequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered by the customer
in lieu of significant transmission system modifications.
No
Individual
Marty Berland
Progress Energy
No
Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect to conditional allowance of
curtailing Firm Transmission Service, which is addressed in the second paragraph of the proposed new footnote (b).
PE remains concerned, however, that the first paragraph of the proposed new footnote (b) does not allow for
curtailment of non-radial non-consequential load. The ability to curtail non-consequential load in the planning horizon
can be a useful tool to mitigate local area issues, and has not been detrimental to the Bulk Electric System (BES).
Disallowing the curtailment of non-radial non-consequential load essentially prohibits taking action in situations in which
the load in question is clearly at a localized self-contained level of the system, i.e. the distribution system(s) served by
the Transmission Owner/Operator. Prohibiting the curtailment of local load thus constitutes regulating distribution
feeder reliability rather than BES reliability. Events that could be mitigated through the curtailment of local, non-radial
non-consequential load are infrequent, and such curtailment has no material effect on the reliability of the BES. PE
therefore suggests that the following addition (item (3)) to the first paragraph of the proposed footnote (b) be
considered: “No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served by the
elements that are removed from service as a result of the Contingency, and/or (2) Planned or controlled interruption of

Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where that Load
must be interrupted to meet performance requirements only on those now radial Transmission Facilities, and/or (3)
Planned or controlled interruption of any additional Load required to mitigate the post-contingency results, provided that
the non-consequential load being shed for the event is localized, and provided that the total load shed for the event
does not exceed 2% of the Planned system peak demand or 200 MW, whichever value is less.”
Yes
There is the potential for conflict between Table 1 – Footnote (b) as currently proposed, which can be considered to
regulate local distribution reliability without improving BES reliability, and local service reliability issues which are under
the purview of state regulatory agencies. For example, the North Carolina Utilities Commission (NCUC) commented
regarding this concern in the ballot which ended March 1 in Project 2006-02. Specifically, NCUC commented that they
were “…concerned that the requirement prohibiting loss of non-consequential load for events in Table 1 of TPL-001-1
is an inappropriate overreach into service issues that are more appropriately addressed by state regulatory
commissions…” Progress Energy believes that NCUC’s concerns are legitimate. BES reliability should address the
avoidance and mitigation of cascading outages and BES facility damage, rather than limited, controlled local area loss
of load, in order to avoid this conflict and overlap of regulation.
Group
Yes
Yes
This is not an issue for historic PJM members, but as PJM has expanded and as a result of the merger of historic
councils into RFC, I am aware that not all regions had standards equal to those of MAAC, and this has been an issue
worked out between transmission planners (historic transmission owners) and their local regulators. It is ultimately a
cost issue for loss of local load that does not affect the overall reliability of the interconnected BES.
Individual
Michael R. Lombardi
Northeast Utilities
Yes
Yes
Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can be better defined as the
proposed revision is subject to interpretation by the different entities and regulatory agencies. Future conflicts can be
minimized by further clarifying the proposed revision. Also, NU is concerned that this new modification does not specify
the amount of permissible load shed nor does it require the planning entity to minimize load shedding under this
exception.
Individual
Charles Lawrence
American Transmission Company
No
For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the
customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also allowed, if the
tripping of the load is either accepted or volunteered by the customer in lieu of significant transmission system
modifications.
No
Group
Yes
Yes
It should be noted that conflicts may arise between individual state commissions, who may have rate recovery
authority, and utilities who attempt to abide explicitly with FERC’s position on non-consequential load loss. In RM-0616-009, the Commission again references Order 693 and specifically highlights comments by Duke Power Company
and Northern Indiana Public Service Company by saying the arguments made to date to allow non-consequential load
loss after a single contingency event is “based largely on the matter of economics, not reliability, with the underlying
premise that it is not economically feasible to invest in the bulk electric system to the point that it can continue service
to all firm load customers under some specific N-1 scenarios.” In the US, State commissions with rate recovery
authority may take the position that considering the economics of proposed investments intended to prevent nonconsequential loss of small or remote load is acceptable. This potential conflict between state and federal positions
could place utilities in a compromising position. Similar conflicts may also exist in Canada.
Individual

Greg Rowland
Duke Energy
No
Duke Energy voted "Negative" on the initial and current ballots of TPL-001-1, primarily because Duke believes that the
requirement prohibiting loss of non-consequential load for P1, P2.1 and P3 events is an overreach by the standard into
local load quality of service issues. We also sought rehearing on the Commission’s March 18 Order Setting Deadline
for Compliance (Docket No. RM06-16), with respect to this and other issues. We believe that FERC’s directive in that
Order to prohibit the loss of non-consequential load in the event of a single contingency appears to extend beyond
measures needed for “reliable operation” of the bulk-power system to prevent “instability, uncontrolled separation or
cascading failures,” none of which occur when utilities implement a planned and orderly loss of non-consequential load.
Hence, the Commission’s directive to prohibit utilities from incorporating carefully controlled loss of non-consequential
load into their planning protocols appears to extend the Commission’s reach beyond its review of measures that are
needed for “reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power Act into
the jurisdiction of state commissions which generally have responsibility for overseeing quality of service issues
applicable to local load. While the current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the recently balloted version of TPL-001-1, it still does not allow Transmission
Planners to use appropriate discretion regarding loss of non-consequential load. Transmission Planners, customers,
and local regulators should jointly control the decision making when BES reliability is not an issue. Often, the events
are extremely improbable and the consequences of these events are local in nature, only requiring minor additional
loss of local load to avoid the potential impacts (environmental, historical, archaeological, aesthetic…) of major
projects. In many instances, it may be in the best interest of all involved parties from an overall cost/benefit point of
view to allow loss of non-consequential load. Duke offers the following ideas on alternatives for the SDT to consider
that will allow for appropriate discretion and facilitate proper planning while allowing non-consequential load loss
(NCLL). The standard should allow for dropping of limited amounts of non-consequential load in situations where it
would be reasonable for a bounded time period and under restricted system conditions (e.g. 1-3 years only when load
is >90 % of peak conditions). Dropping of non-consequential load would be prudent planning in situations where the
near term impact of load projections or implementation of nearby transmission/generation projects will alleviate the
necessity of an upgrade to meet N-1 conditions. Also, reliability of service to end-use customer is impacted by the
entire system from source to load. Where allowance for NCLL would not greatly impact individual end-use customers’
level of reliability the transmission planner should consider its use. Normally transmission system outages are a minor
contributor to overall customer outage frequency and duration. Instances where allowance for NCLL can be used to
avoid projects without greatly impacting a customer’s outage frequency and duration should be acceptable. Use of
reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be considered by the SDT for determination of acceptable use of
NCLL.
Yes
See response to question #1.
Individual
Bill Middaugh
Tri-State Generation and Transmission Association, Inc.
No
Tri-State does believe that the new footnote is an improvement, but thinks there are still some changes necessary. We
believe that the word “only” should be removed from the phrase “…where that Load must be interrupted to meet
performance requirements only on those now radial Transmission Facilities” because that discrimination was not
required in FERC Order RM-06-16-009. There may be times when facilities near the temporary radial facilities might
also fall outside the limits set in reliability criteria but the situation is mitigated if the load shedding occurs at the radial
facility. The meaning of the second paragraph of the new footnote is unclear. Tri-State recommends changing it to
"Curtailment of Firm Transmission Service is not allowed unless it is coupled with curtailment-offsetting resources that
are obligated to re-dispatch. Further, the curtailment activities cannot result in the shedding of any Firm load or in
violations of Facility Ratings, either internal or external to the planning region."
Yes
We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of non-consequential load in the
event of a single contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power
system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when utilities
implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive to prohibit utilities
from incorporating carefully controlled loss of non-consequential load into their planning protocols appears to extend
the Commission’s reach beyond its review of measures that are needed for “reliable operation” of the bulk-power
system as defined under Section 215 of the Federal Power Act. Such directive constitutes an overreaching of the
Commission’s jurisdiction under Section 215 of the Federal Power Act into the jurisdiction of state commissions which
generally have responsibility for overseeing quality of service issues applicable to local load.
Group
Yes

Yes
This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all honesty, shedding load for local
area impacts has nothing to do with BES reliability and should not be under FERC jurisdiction under Section 215 of the
Federal Power Act, but rather State jurisdiction for quality of service issues. However, there is also the matter of FERC
jurisdiction over commercial matters and the opportunity to “game” the original footnote by transmission providers by
allowing firm load shedding to grant firm transmission service for themselves, thereby avoiding or deferring
transmission investment, while at the same time denying or requiring others to build the same transmission avoided in
order to obtain transmission service. We can see how difficult it is from a drafting team’s perspective in achieving a
balanced position between these different matters. The drafting team should be applauded for finding a reasonable
position.
Individual
Roger Champagne
Hydro-Québec TransÉnergie (HQT)
No
The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission again
references Order 693 and specifically highlights comments by Duke Power Company and Northern Indiana Public
Service Company by saying the arguments made to date to allow non-consequential load loss after a single
contingency event is “based largely on the matter of economics, not reliability, with the underlying premise that it is not
economically feasible to invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.” The proposed changes to footnote ‘b’ indicate “No interruption of firm
Load is allowed except:… (2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet performance
requirements only on those now radial Transmission Facilities.” The exception described appears to still allow nonconsequential load loss. FERC describes in RM06-16-009 non-consequential load loss as “the removal, by any means,
of any firm load that is not directly served by the elements that are removed from service as a result of the
contingency.” In referencing Order 693, the Commission reiterated its position that TPL standards “should not allow an
entity to plan for the loss of non-consequential load in the event of a single contingency.” “Must” should be used instead
of “should” in the last sentence of the footnote, making it to read “Facility Ratings in those regions must also be
respected.”
Yes
Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities who
attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with rate recovery
authority may take the position that considering the economics of proposed investments intended to prevent nonconsequential loss of small or remote load is acceptable. This potential conflict between state and federal positions
could place utilities in a compromising position.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES and Firm Demand and on the
understanding that the NERC standards apply only to the BES as defined in the NERC Glossary as follows: “As
defined by the Regional Reliability Organization, the electrical generation resources, transmission lines,
interconnections with neighboring systems, and associated equipment, generally operated at voltages of 100 kV or
higher. Radial transmission facilities serving only load with one transmission source are generally not included in this
definition.” To be clear, our interpretation of the present definition of BES is that it defers to each Regional Reliability
Organization to define the elements of the power system that are considered BES and, therefore in the NPCC Region,
"BES as defined by NERC" = "BPS as defined by NPCC".
No

Consideration of Comments on Project 2010-11: TPL Table 1 Order and
Comments Submitted with Initial Ballots
The Standards Committee thanks all commenters who submitted comments on the
proposed SAR for the TPL Table 1 Order. The SAR proposed changes to TPL Table 1 in
response to FERC’s Order RM06-16-009 which required the ERO to clarify TPL-002-0, Table
1 - footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single contingency occurs on a transmission system. Such clarification was originally
required by June 30, 2010. Table 1 is used in TPL-001, TPL-002, TPL-003, and TPL-004 –
and any change to Table 1 needs to be reflected in all four of these TPL standards. (Note:
FERC issued a clarifying order on June 11, 2010 which extended the deadline for clarifying
Table 1 until March 31, 2011.)
The SAR, implementation plan, and the clean and redline versions to the four TPL standards
were posted for a 40-day public comment period from April 15, 2010 through May 27, 2010.
Stakeholders were asked to provide feedback on the standards through a special electronic
comment form. There were 22 sets of comments, including comments from more than 80
different people from approximately 40 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.
The initial ballot for the proposed changes to the four TPL standards was conducted from
May 17-27, 2010. The comments submitted with initial ballots and the drafting team’s
responses to those comments are contained in this report.
All comments submitted during the comment period and the initial ballot results are posted
on the following page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Based on stakeholder comments, the drafting team has made some additional changes to
Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes include
the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the
terminology used in the associated column heading of Table 1 – ‘Loss of Demand or
Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology
changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear
to the SDT from the cited inputs that there were still a number of concerns with the
proposed clarification. In particular, entities were concerned that the proposal was still
unclear and too limiting on the proposed conditions when load could be interrupted. Also,
there were numerous concerns raised on jurisdictional issues with regard to interrupting
Demand. In short, the needed clarification hadn’t been achieved. Therefore, the SDT
continued discussions on different alternatives to address the needed clarification. This led
the SDT to focus on identifying constraining parameters such as the amount of Demand that
could be interrupted, annual amount of exposure, etc.

In order to receive additional industry feedback on the new approach, a Technical
Conference was held on August 10, 2010 to address four specific questions arising from the
FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to
plan to shed non-consequential firm load for a single contingency (Category B)? Please
provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be applied at the fringes of a system.
Is this limitation appropriate and if so, please define it? What other specific criteria
could be applied to limit the planned use of non-consequential firm load loss for a single
contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B), what
changes to your transmission plan would be required? Please quantify your response to
the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be handled on a case-by-case basis
with affected entities asking for an exception from the ERO. Could you support such a
process? If your response is no, then what process would you suggest? If your
response is yes, then what technical criteria should be developed to identify and
evaluate cases?
In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand is appropriate in certain
limited circumstances and that such usage is not widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’
could possibly be discriminatory.



If interruption of non-consequential Demand were not allowed, such a policy would
result in significant costs to customers for limited benefits.



A case-by-case exception process that requires ERO or FERC approval was not
viewed as an acceptable approach due to possible inconsistencies in approach and
potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to
leverage the existing work with the industry comments to develop an acceptable clarification
to footnote ‘b’. This led to the approach shown in the 2nd posting where the SDT has taken
the concept of allowing interruption of Demand without numerical constraints in an open
and transparent stakeholder process to review and accept such plans. This open and
transparent stakeholder process is seen as an enhancement of existing entity processes
without the problems associated with an ERO or FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693
directives (and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an
equal and effective method and that should be acceptable to all concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always
acceptable to use Interruptible Demand and Demand-Side Management:


Interruptible Demand or Demand-Side Management

The above changes will be noted to stakeholders in a separate posting before the initiation
of another ballot.
The revised Footnote ‘b’ is:

b) An objective of the planning process is to avoid interruption of Demand. Interruption
of Demand is discouraged and measures to mitigate such interruption should be
pursued within the planning process. However, Demand may need to be interrupted in
limited circumstances to address BES performance requirements. When interruption
of Demand is utilized within the planning process, such interruption is limited to:


Demand that is directly served by the elements that are removed from service as
a result of the Contingency



Interruptible Demand or Demand-Side Management



Demand that does not adversely impact overall BES reliability where the
circumstances describing the use of such Demand interruption are documented,
including alternatives evaluated; and where the application is subject to review
and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions would also be
respected.

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected] In addition, there is
a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Comments and Responses from Formal Comment Period: 
1. 

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system by June 30, 2010. Do you agree with the proposed changes and if not, please provide specific
reasons for your disagreement. .......................................................................................................................... 10 

2. 

Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any regulatory function,
rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the conflict. .................................. 25

Comments and Responses from Initial Ballot: 
3. 

Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010 ..................................... 30 

August 30, 2010

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Commenter

Organization

Industry Segment
1

1.

Group

Guy Zito
Additional Member

2

3

4

5

6

8

9

10

Northeast Power Coordinating Council

X

Additional Organization

Region

Segment Selection

1. Alan Adamson

New York State Reliability Council

NPCC

10

2. Greg Campoli

New York Independent System Operator

NPCC

2

3. Roger Champagne

Hydro-Quebec TransEnergie

NPCC

2

4. Kurtis Chong

Independent Electricity System Operator

NPCC

2

5. Sylvain Clermont

Hydro-Quebec TransEnergie

6. Chris de Graffenried

Consolidated Edison Co. of New York, Inc.

NPCC

1

7. Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

8. Ben Eng

New York Power Authority

NPCC

4

9. Brian Evans-Mongeon

Utility Services

NPCC

8

10. Mike Garton

Dominion Resources Services, Inc.

NPCC

5

11. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

12. Kathleen Goodman

ISO - New England

NPCC

2

13. David Kiguel

Hydro One Networks Inc.

NPCC

1

14. Peter Yost

Consolidated Edison Co. of New York, Inc.

NPCC

3

August 30, 2010

7

1

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6

15. Randy MacDonald

New Brunswick System Operator

NPCC

2

16. Bruce Metruck

New York Power Authority

NPCC

6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18. Robert Pellegrini

The United Illuminating Company

NPCC

1

19. Saurabh Saksena

National Grid

NPCC

1

20. Michael Schiavone

National Grid

NPCC

1

2.

South Carolina Electric & Gas

Group

Philip R. Kleckley
Additional Member

X

Additional Organization

X
Region

Southern Company Services - Trans.

SERC

1

Tennessee Valley Authority

SERC

1

3. Charles Long

Entergy

SERC

1

4. James Manning

North Carolina Electric Membership Corporation

SERC

3

5. Pat Huntley

SERC Reliability Corporation

SERC

10

John Bee

Exelon Transmission Strategy & Compliance

Additional Member

X

Additional Organization

X
Region

Segment Selection

:(ComEd)

RFC

1

2. Weaver, David W

(PECO)

RFC

1

3. McHugh, Kathleen P

(PECO)

RFC

1

4. Kay, Thomas W

(ComEd)

RFC

1

5. Szymczak, Ronald

(ComEd)

RFC

1

6. Chu, Ron F

(PECO)

RFC

1

7. Donnelly, Michael J

(PECO)

RFC

1

8. Kliros, Chris B

(ComEd)

RFC

1

9. Mills, Paul M

(ComEd)

RFC

1

10. Webb, Becky

(ComEd)

RFC

1

Group

Denise Koehn

August 30, 2010

BPA, Transmission Reliability Program

X

X

10

X

1. Mortenson, Eric

4.

9

Segment Selection

2. David Marler

Group

8

X

1. Bob Jones

3.

7

X

X

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

Additional Member

2

Additional Organization

3

4

5

6

Region

BPA, Transmission Planning

WECC

1

2. Berhanu Tesema

BPA, Transmission Planning

WECC

1

3. Larry Furumasu

BPA, Transmission Planning

WECC

1

4. Kyle Kohne

BPA, Transmission Planning

WECC

1

5. Don Watkins

BPA, Transmission System Operations

WECC

1

6. Rebecca Berdahl

BPA, Power, Long Term Sales and Purchases

WECC

3

Group

Carol Gerou
Additional Member

Additional Organization

Region

Segment Selection

MRO

1

2. Tom Webb

Wisconsin Public Service

MRO

3, 4, 5, 6

3. Terry Bilke

Midwest ISO Inc.

MRO

2

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

7. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

8. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

Richard Kafka

Pepco Holdings, Inc.

Additional Member

X

X

Additional Organization

X

X

Region

Segment Selection

1. Jim Summers

Delmarva Power and Light Co.

RFC

1

2. John Radman

Potomac Electric Power Company

RFC

1

7.

Group

Ben Li
Additional Member

August 30, 2010

10

X

American Transmission Company

Group

9

Midwest Reliability Organization

1. Chuck Lawrence

6.

8

Segment Selection

1. Chuck Matthews

5.

7

IESO

X
Additional Organization

Region

Segment Selection

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

1. Bill Phillips

MISO

MRO

2. James Castle

NYISO

NPCC

3. Charles Yeung

SPP

SPP

4. Lourdes Estrada-Salinero

CAISO

WECC

5. Patrick Brown

PJM

RFC

6. Steve Myers

ERCOT

ERCOT

8.

Group

Frank Gaffney

Florida Municipal Power Agency

Additional Member

2

3

X

Additional Organization

4

5

6

X

X

X

Region

Utilities Commission of New Smyrna Beach

FRCC

4

2. Greg Woessner

Kissimmee Utility Authority

FRCC

1

3. Jim Howard

Lakeland Electric

FRCC

1

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services

FRCC

1

6. Cairo Vanegas

Fort Pierce Utility Authority

FRCC

4

Individual

Stephen Mizelle

Southern Company Transmission

X

Robert Casey

Georgia Transmission Corporation (Bulk
System Planning)

X

Individual
11.

Individual

Thad Ness

American Electric Power

X

X

X

X

12.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

13.

Individual

Martin Bauer

US Bureau of Reclamation

14.

Individual

Kirit Shah

Ameren

X

X

X

15.

Individual

Robert W. Roddy

Dairyland Power Cooperative

X

X

X

10.

August 30, 2010

8

9

10

Segment Selection

1. Timothy Beyrle

9.

7

X
X

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6
X

16.

Individual

Marty Berland

Progress Energy

X

X

X

17.

Individual

Michael R. Lombardi

Northeast Utilities

X

X

X

18.

Individual

Charles Lawrence

American Transmission Company

X

19.

Individual

Greg Rowland

Duke Energy

X

X

X

X

X

X

X

Bill Middaugh

Tri-State Generation and Transmission
Association, Inc.

X

Individual
21.

Individual

Roger Champagne

Hydro-Québec TransEnergie (HQT)

X

22.

Individual

Dan Rochester

Independent Electricity System Operator

20.

August 30, 2010

7

8

9

10

X

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which
required the ERO to clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system by June 30, 2010. Do you agree with the proposed
changes and if not, please provide specific reasons for your disagreement.
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made
changes to the footnote to balance the various industry concerns while assuring BES reliability.
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology used in the associated column heading of Table 1 –
‘Loss of Demand or Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the SDT from the cited inputs that there were still a
number of concerns with the proposed clarification. In particular, entities were concerned that the proposal was still unclear and too limiting on the
proposed conditions when load could be interrupted. Also, there were numerous concerns raised on jurisdictional issues with regard to
interrupting Demand. In short, the needed clarification hadn’t been achieved. Therefore, the SDT continued discussions on different alternatives
to address the needed clarification. This led the SDT to focus on identifying constraining parameters such as the amount of Demand that could be
interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference was held on August 10, 2010 to address four
specific questions arising from the FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to plan to shed non-consequential firm load for a single
contingency (Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency (Category B) could be
applied at the fringes of a system. Is this limitation appropriate and if so, please define it? What other specific criteria could be applied to limit
the planned use of non-consequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of non-consequential firm load allowed for a single contingency event
(Category B), what changes to your transmission plan would be required? Please quantify your response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency (Category B) could be
handled on a case-by-case basis with affected entities asking for an exception from the ERO. Could you support such a process? If your
response is no, then what process would you suggest? If your response is yes, then what technical criteria should be developed to identify
and evaluate cases?

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand was appropriate in certain limited circumstances and that such usage was not
widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could possibly be discriminatory.



If interruption of non-consequential Demand was not allowed, such a policy would result in significant costs to customers for limited benefits.



A case-by-case exception process that required ERO or FERC approval was not viewed as an acceptable approach due to possible
inconsistencies in approach and potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the existing work with the industry comments to
develop an acceptable clarification to footnote ‘b’. This led to the approach shown in this 2nd posting where the SDT has taken the concept of
allowing interruption of Demand without numerical constraints in an open and transparent stakeholder process to review and accept such plans.
This open and transparent stakeholder process is seen as an enhancement of existing entity processes without the problems associated with an
ERO or FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives (and subsequent orders) concerning
clarification to footnote ‘b’ in a way that is an equal and effective method and that should be acceptable to all concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable to use Interruptible Demand and Demand-Side
Management:


Interruptible Demand or Demand-Side Management

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:




(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
Interruptible Demand or Demand-Side Management
(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization

Yes or No

Question 1 Comment

Duke Energy

No

Duke Energy voted "Negative" on the initial and current ballots of TPL-001-1, primarily because Duke believes
that the requirement prohibiting loss of non-consequential load for P1, P2.1 and P3 events is an overreach by
the standard into local load quality of service issues. We also sought rehearing on the Commission’s March
18 Order Setting Deadline for Compliance (Docket No. RM06-16), with respect to this and other issues. We
believe that FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of a
single contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power
system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many instances, it may be in the
best interest of all involved parties from an overall cost/benefit point of view to allow loss of non-consequential
load.
Duke offers the following ideas on alternatives for the SDT to consider that will allow for appropriate discretion
and facilitate proper planning while allowing non-consequential load loss (NCLL).The standard should allow
for dropping of limited amounts of non-consequential load in situations where it would be reasonable for a

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
bounded time period and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations where the near term
impact of load projections or implementation of nearby transmission/generation projects will alleviate the
necessity of an upgrade to meet N-1 conditions. Also, reliability of service to end-use customer is impacted by
the entire system from source to load. Where allowance for NCLL would not greatly impact individual enduse customers’ level of reliability the transmission planner should consider its use. Normally transmission
system outages are a minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to avoid projects without greatly impacting a customer’s outage frequency
and duration should be acceptable. Use of reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be
considered by the SDT for determination of acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Midwest Reliability Organization

August 30, 2010

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Dairyland Power Cooperative

No

DPC concurs with the MRO comments: For Footnote b, add a third exception to the list, "or (3) end-use load
that is either accepted or volunteered by the customer". It is a widely-held understanding that the tripping of
non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered
by the customer in lieu of significant transmission system modifications.

American Transmission
Company

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Response: The SDT has added the second bullet to address your concern.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Georgia Transmission
Corporation (Bulk System
Planning)

Yes or No

Question 1 Comment

No

Georgia Transmission Corporation (GTC) believes that the requirement prohibiting loss of non-consequential
load for P1, P2.1 and P3 events is an overreach by the standard into local load quality of service issues. We
believe that FERC’s directive in (Docket No. RM06-16) to prohibit the loss of non-consequential load in the
event of a single contingency appears to extend beyond measures needed for “reliable operation” of the bulkpower system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the cost of major projects. In
many instances, it may be in the best interest of all involved parties from an overall cost/benefit point of view
to allow loss of non-consequential load.
We also note that on April 19 NERC filed a request for rehearing with FERC asking that the Commission
revise the directive in Paragraph 8 of the March 18 TPL-002 Order to allow NERC the necessary time to
incorporate changes to the TPL-002 Reliability Standard through the Reliability Standards Development
Process that are necessary to achieve bulk power system reliability. NERC also requested that the
Commission grant NERC’s Motion for Stay to stay the Order so that a public technical conference with
opportunity for comment can be held in order to provide parties an opportunity to meet and discuss the
technical considerations of developing a modification to the TPL-002 standard that prohibits the loss of nonconsequential firm load in the event of an N-1 contingency. NERC’s April 19 filing pointed out that if the
Commission’s directive to disallow the loss of non-consequential firm load for an N-1 contingency is
implemented, a question is presented regarding whether the Reliability Standard still serves the purpose of
ensuring the Reliable Operation of the bulk power system by preventing instability, uncontrolled separation,
and cascading failures. That is, the Commission’s directive sets forth an expectation that NERC is to
implement standards that address all loss of load at costs that may not be commensurate with bulk power
system reliability, as statutorily defined, which is fundamentally different from what the Reliability Standards
were intended to do.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

various industry concerns while assuring BES reliability. .
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Progress Energy

August 30, 2010

No

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect to conditional
allowance of curtailing Firm Transmission Service, which is addressed in the second paragraph of the
proposed new footnote (b). PE remains concerned, however, that the first paragraph of the proposed new
footnote (b) does not allow for curtailment of non-radial non-consequential load. The ability to curtail nonconsequential load in the planning horizon can be a useful tool to mitigate local area issues, and has not been
detrimental to the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly at a localized selfcontained level of the system, i.e. the distribution system(s) served by the Transmission Owner/Operator.
Prohibiting the curtailment of local load thus constitutes regulating distribution feeder reliability rather than
BES reliability. Events that could be mitigated through the curtailment of local, non-radial non-consequential
load are infrequent, and such curtailment has no material effect on the reliability of the BES.

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
PE therefore suggests that the following addition (item (3)) to the first paragraph of the proposed footnote (b)
be considered:”No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served
by the elements that are removed from service as a result of the Contingency, and/or (2) Planned or
controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now
radial Transmission Facilities, and/or (3) Planned or controlled interruption of any additional Load required to
mitigate the post-contingency results, provided that the non-consequential load being shed for the event is
localized, and provided that the total load shed for the event does not exceed 2% of the Planned system peak
demand or 200 MW, whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
various industry concerns while assuring BES reliability. The SDT did not adopt numerical limits as a single nation-wide value was not seen as equitable for all
entities.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Hydro-Québec TransEnergie

August 30, 2010

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

(HQT)

Question 1 Comment
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Northeast Power Coordinating
Council

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Response: The SDT believes that it has been responsive to the FERC directive in that the standards development process has been employed. In the
development of the footnote, the SDT has balanced the need for discretion while addressing local area concerns with the need to assure the reliability of the BES.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

‘Must’ is not appropriate in a footnote as it would impose a requirement in the footnote. The SDT has replaced ‘should’ with ‘would’ to correct the grammar.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Tri-State Generation and
Transmission Association, Inc.

No

Tri-State does believe that the new footnote is an improvement, but thinks there are still some changes
necessary. We believe that the word “only” should be removed from the phrase “...where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities” because that
discrimination was not required in FERC Order RM-06-16-009. There may be times when facilities near the
temporary radial facilities might also fall outside the limits set in reliability criteria but the situation is mitigated
if the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State recommends changing it to
"Curtailment of Firm Transmission Service is not allowed unless it is coupled with curtailment-offsetting
resources that are obligated to re-dispatch. Further, the curtailment activities cannot result in the shedding of
any Firm load or in violations of Facility Ratings, either internal or external to the planning region."

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

various industry concerns while assuring BES reliability.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Southern Company Transmission

No

We propose that the section in double parentheses be deleted. The proposed wording by the drafting team
seems to imply that the curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language stated only that
curtailments were permitted to prepare for the next contingency, not to address loading related to the initial
contingency. The proposed wording could be interpreted to allow redispatch/firm curtailments to address any
single contingency constraint.
Southern Companies recommend that the original language relating to “preparing for the next contingency” be
incorporated into the drafting team’s proposal.((Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted element or by the
affected area, may occur in certain areas without impacting the overall reliability of the interconnected
transmission systems. To prepare for the next contingency, system adjustments are permitted, including

August 30, 2010

20

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
curtailments of contracted Firm (non-recallable reserved) electric power Transfers.)) No interruption of firm
Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities. To prepare
for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (nonrecallable reserved) electric power transfers No curtailment of Firm Transmission Service is allowed except
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch. where it can It must be
demonstrated that Facilities remain within applicable Facility Ratings and those adjustments do not result in
the shedding of any firm Load. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions should also be respected.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the
Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in
the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity is obligated to re-dispatch
its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the
affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words
“To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your
comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

August 30, 2010

21

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
South Carolina Electric & Gas

Yes

For better clarity delete the phrase “when coupled with” in the second paragraph of footnote ‘b.’

Response: The SDT did not delete the suggested phrase as it believes it is correct as stated but added commas to make the phrase read more clearly.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Independent Electricity System
Operator

August 30, 2010

Yes

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES and Firm Demand
and on the understanding that the NERC standards apply only to the BES as defined in the NERC Glossary
as follows:”As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally operated
at voltages of 100 kV or higher. Radial transmission facilities serving only load with one transmission source
are generally not included in this definition.” To be clear, our interpretation of the present definition of BES is

22

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
that it defers to each Regional Reliability Organization to define the elements of the power system that are
considered BES and, therefore in the NPCC Region, "BES as defined by NERC" = "BPS as defined by
NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
BPA, Transmission Reliability
Program

Yes

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with "Firm Transfers" to
be consistent with the fourth column of the existing Table 1 Transmission System Standards - Normal and
Emergency Conditions.

Response: The SDT agrees and has made the change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
American Electric Power

August 30, 2010

Yes

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Exelon Transmission Strategy &
Compliance

Yes

Florida Municipal Power Agency

Yes

IESO

Yes

Northeast Utilities

Yes

Pepco Holdings, Inc.

Yes

US Bureau of Reclamation

Yes

Manitoba Hydro

Yes

MH agrees with the SDT proposal.

Ameren

Yes

We were ok with the previous language. Though we do not intend to drop non-consequential load for a single
contingency, we undersatnd that other ares may have been following such practice without degarding the
relaibility of BES. We believe that they can continue this practice if they develop non-firm contracts with these
customers.

Response: Thank you for your support. Several stakeholders proposed additional modifications and the drafting team did make several additional modifications to
the footnote – please see the revised footnote.

August 30, 2010

24

Consideration of Comments on TPL Table 1 Order — Project 2010-11

2. Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the
conflict.
Summary Consideration: The SDT understands that there may be conflicts as pointed out by respondents; however, the SDT believes that
there should be constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES. Strict
numerical constraints applied across all of North America were not seen as appropriate. Instead, the SDT is leveraging existing processes to
require documentation of Demand to be interrupted including alternatives evaluated and for the situation to be vetted in an open and transparent
stakeholder process.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
Interruptible Demand or Demand-Side Management

o
o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization
Ameren

Yes or No

Question 2 Comment

No

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

American Electric Power

No

American Transmission
Company

No

BPA, Transmission Reliability
Program

No

Dairyland Power Cooperative

No

Exelon Transmission Strategy &
Compliance

No

Independent Electricity System
Operator

No

Manitoba Hydro

No

Midwest Reliability Organization

No

Southern Company Transmission

No

US Bureau of Reclamation

No

South Carolina Electric & Gas

No

Question 2 Comment

The comments expressed herein represent a consensus of the views of the above named members of the
SERC Engineering Committee Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.

Response: Thank you for your response. Several stakeholders proposed additional modifications and the drafting team did make several additional modifications
to the footnote – please see the revised footnote.
Hydro-Québec TransEnergie
(HQT)

August 30, 2010

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment
between state and federal positions could place utilities in a compromising position.

Northeast Power Coordinating
Council

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

IESO

Yes

It should be noted that conflicts may arise between individual state commissions, who may have rate recovery
authority, and utilities who attempt to abide explicitly with FERC’s position on non-consequential load loss. In
RM-06-16-009, the Commission again references Order 693 and specifically highlights comments by Duke
Power Company and Northern Indiana Public Service Company by saying the arguments made to date to
allow non-consequential load loss after a single contingency event is “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to invest in the bulk
electric system to the point that it can continue service to all firm load customers under some specific N-1
scenarios.” In the US, State commissions with rate recovery authority may take the position that considering
the economics of proposed investments intended to prevent non-consequential loss of small or remote load is
acceptable. This potential conflict between state and federal positions could place utilities in a compromising
position.Similar conflicts may also exist in Canada.

Progress Energy

Yes

There is the potential for conflict between Table 1 - Footnote (b) as currently proposed, which can be
considered to regulate local distribution reliability without improving BES reliability, and local service reliability
issues which are under the purview of state regulatory agencies. For example, the North Carolina Utilities
Commission (NCUC) commented regarding this concern in the ballot which ended March 1 in Project 200602. Specifically, NCUC commented that they were “...concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1 is an inappropriate overreach into service issues that
are more appropriately addressed by state regulatory commissions...” Progress Energy believes that NCUC’s
concerns are legitimate. BES reliability should address the avoidance and mitigation of cascading outages
and BES facility damage, rather than limited, controlled local area loss of load, in order to avoid this conflict
and overlap of regulation.

Response: The SDT understands the issue; however, the SDT believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES. Strict numerical constraints applied across all of North America were not seen as appropriate. Instead, the SDT
is leveraging existing processes to require documentation of Demand to be interrupted including alternatives evaluated and for the situation to be vetted in an
open and transparent stakeholder process.

August 30, 2010

27

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Northeast Utilities

Yes or No

Question 2 Comment

Yes

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can be better defined as
the proposed revision is subject to interpretation by the different entities and regulatory agencies. Future
conflicts can be minimized by further clarifying the proposed revision.
Also, NU is concerned that this new modification does not specify the amount of permissible load shed nor
does it require the planning entity to minimize load shedding under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process. However, Demand
may need to be interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial Transmission
FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustmentsthe
re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning
region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Duke Energy

Yes

See response to question #1.

Georgia Transmission
Corporation (Bulk System
Planning)

Yes

See response to Question #1.

August 30, 2010

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Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

Response: See response to question #1.
Florida Municipal Power Agency

Yes

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all honesty, shedding load
for local area impacts has nothing to do with BES reliability and should not be under FERC jurisdiction under
Section 215 of the Federal Power Act, but rather State jurisdiction for quality of service issues. However,
there is also the matter of FERC jurisdiction over commercial matters and the opportunity to “game” the
original footnote by transmission providers by allowing firm load shedding to grant firm transmission service
for themselves, thereby avoiding or deferring transmission investment, while at the same time denying or
requiring others to build the same transmission avoided in order to obtain transmission service. We can see
how difficult it is from a drafting team’s perspective in achieving a balanced position between these different
matters. The drafting team should be applauded for finding a reasonable position.

Pepco Holdings, Inc.

Yes

This is not an issue for historic PJM members, but as PJM has expanded and as a result of the merger of
historic councils into RFC, I am aware that not all regions had standards equal to those of MAAC, and this
has been an issue worked out between transmission planners (historic transmission owners) and their local
regulators. It is ultimately a cost issue for loss of local load that does not affect the overall reliability of the
interconnected BES.

Yes

We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of non-consequential load
in the event of a single contingency appears to extend beyond measures needed for “reliable operation” of the
bulk-power system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur
when utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their
planning protocols appears to extend the Commission’s reach beyond its review of measures that are needed
for “reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act.
Such directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal
Power Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality
of service issues applicable to local load.

Response: Thank you for your support.
Tri-State Generation and
Transmission Association, Inc.

Response: The SDT is not in a position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES. Such constraints would be determined
through the open and transparent stakeholder process.

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

3. Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made changes to
the footnote to balance the various industry concerns while assuring BES reliability.
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology used in the associated column
heading of Table 1 – ‘Loss of Demand or Curtailed Firm Transfers.’ For additional clarity, the team made the following
terminology changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the SDT from the cited inputs that
there were still a number of concerns with the proposed clarification. In particular, entities were concerned that the proposal
was still unclear and too limiting on the proposed conditions when load could be interrupted. Also, there were numerous
concerns raised on jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t been
achieved. Therefore, the SDT continued discussions on different alternatives to address the needed clarification. This led the
SDT to focus on identifying constraining parameters such as the amount of Demand that could be interrupted, annual amount
of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference was held on August 10, 2010 to
address four specific questions arising from the FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to plan to shed non-consequential firm
load for a single contingency (Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency
(Category B) could be applied at the fringes of a system. Is this limitation appropriate and if so, please define it? What
other specific criteria could be applied to limit the planned use of non-consequential firm load loss for a single contingency
(Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of non-consequential firm load allowed for a single
contingency event (Category B), what changes to your transmission plan would be required? Please quantify your response
to the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm load for a single contingency
(Category B) could be handled on a case-by-case basis with affected entities asking for an exception from the ERO. Could

August 30, 2010

30

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

you support such a process? If your response is no, then what process would you suggest? If your response is yes, then
what technical criteria should be developed to identify and evaluate cases?
In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand was appropriate in certain limited circumstances and that such
usage was not widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could possibly be discriminatory.



If interruption of non-consequential Demand was not allowed, such a policy would result in significant costs to customers for
limited benefits.



A case-by-case exception process that required ERO or FERC approval was not viewed as an acceptable approach due to
possible inconsistencies in approach and potential unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the existing work with the
industry comments to develop an acceptable clarification to footnote ‘b’. This led to the approach shown in this 2nd posting
where the SDT has taken the concept of allowing interruption of Demand without numerical constraints in an open and
transparent stakeholder process to review and accept such plans. This open and transparent stakeholder process is seen as an
enhancement of existing entity processes without the problems associated with an ERO or FERC case-by-case exception
process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives (and subsequent orders)
concerning clarification to footnote ‘b’ in a way that is an equal and effective method and that likely will be acceptable to all
concerned parties.
In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable to use Interruptible Demand
and Demand-Side Management:


Interruptible Demand or Demand-Side Management

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to:

August 30, 2010

31

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

o (1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or
o Interruptible Demand or Demand-Side Management
o (2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of
the Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Voter
Rodney
Phillips

Entity
Allegheny Power

Segment

Vote

Comment

1

Negative

Allegheny Power believes the loss of non-consequential load and/or curtailment of
transmission service for N-1 contingencies should be limited to only extreme circumstances.
Exception 2 of footnote b allows for the loss of non-consequential load for N-1
contingencies with no restriction. Allegheny Power recommends removing exception 2
footnote b.

Response: The SDT and the majority of the commenters disagree with this suggestion.
Gordon
Rawlings

BC Transmission
Corporation

1

Negative

Faramarz
Amjadi

BC Transmission
Corporation

2

Negative

Hubert C.
Young

South Carolina
Electric & Gas Co.

3

Negative

August 30, 2010

BCTC appreciates the good work of the SAR committee in drafting the changes to Footnote
b of Table 1. BCTC agrees with the drafting team that interruption of firm load, served by
either radial circuits or circuits that have became radial as a result of the contingency,
should be allowed for N-1 contingencies. However, it is our position that interruption of
firm load should not be limited only to such consequential loads. In our view, interruption
of electric supply to some local network customers in the affected area should be
permissible. This inclusion will allow transmission planners to plan BCTC’s regional
transmission network reliably and without impacting neighbouring transmission networks.
SCE&G has significant concern with the proposed revision to TPL Table 1, Footnote B. The
current Footnote B states “Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the
overall reliability of the interconnected transmission systems” is important to the TPL
standards to ensure that ERO standards do not dictate the level of service to customers.
Service to customers and load pockets is jurisdictional to State Commissions and ERO
standards should not compromise this jurisdiction. SCE&G believes that any proposed
revisions to Footnote B must retain the concept that planned or controlled interruption of
electric supply to customers, whether they are radial or network, is allowed as long as it
does not impact the overall reliability of the interconnected transmission systems. The
proposed revision eliminates this concept. There seems to be a general inconsistency and
maybe confusion between the terms “reliability” and “level of service”.

David Frank
Ronk

Consumers Energy

4

Negative

James B
Lewis

Consumers Energy

5

Negative

Hugh A.
Owen

Public Utility
District No. 1 of
Chelan County

6

Negative

The interruption of a small amount of load is, under most conditions, not a risk to the
reliability of the BES and is at times necessary to preserve reliability. The planned
interruption of some load may be a cost effective alternative to a costly transmission
project. That is a quality of service issue.

Michael
Gammon

Kansas City Power
& Light Co.

1

Negative

Charles
Locke

Kansas City Power
& Light Co.

3

Negative

Thomas
Saitta

Kansas City Power
& Light Co.

6

Negative

While the current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the recently balloted version of TPL-001-1, it still does
not allow Transmission Planners to use appropriate discretion regarding loss of nonconsequential load. Transmission Planners, customers, and local regulators should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit

August 30, 2010

The current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the previous version of TPL-001-1. However, it still does
not allow Transmission Planners to use appropriate and necessary discretion regarding loss
of non-consequential load. Transmission Planners, customers, and local regulators should
control the decision making when BES reliability is not an issue. Often, the consequences of
these events are solely local in nature, requiring only minor additional loss of local load to
avoid the costly major projects. In many instances, it may be in the best interest of all
involved parties from an overall cost/benefit point of view to allow loss of nonconsequential load.

33

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
point of view to allow loss of non-consequential load.

Linda Brown

San Diego Gas &
Electric

1

Affirmative

As to item (1), all load served directly by a transmission element which experiences a fault
will be interrupted when the faulted element is taken out of service. This is the natural
relationship between the load and the transmission element. Allowing this for BES elements
may encourage transmission owners to remove transmission instead of upgrading or
replacing it. Consider a load supplied by two transmission lines of different capacity. If the
larger line is lost due to a contingency (N-1) and the remaining smaller line overloads the
transmission owner is left with several options to address the problem: (1) move load
between buses, (2) upgrade the smaller line, (3) add another line, or (4) create a radial
load by removing the smaller line. Number (4) may be the least expensive and allowable
under TPL-002, footnote b.
Item (2) may also encourage transmission owners to develop plans which make load
shedding part of category B. Consider a load served by three transmission lines, a utility
may decide to remove a line, instead of upgrading, in order to set up a situation where an
N-1 contingency would make the bus temporarily radial. In the event of a single outage (N1), the load bus will be temporarily radial and load can be shed at the bus.

W. R.
Schoneck

Florida Power &
Light Co.

3

Affirmative

I believe the language is an improvement and clarifies the intent but I believe there still
should be additional language added to give an exemption in meeting this requirement if it
does not make economic sense(not economically feasible) and has no real impact on the
BES.

Richard J
Kafka

Potomac Electric
Power Co.

1

Affirmative

It is understood that this is a compliance filing issue. This is not an issue for historic PJM
members, but as PJM has expanded and as a result of the merger of historic councils into
RFC, I am aware that not all regions had standards equal to those of MAAC, and this has
been an issue worked out between transmission planners (historic transmission owners)
and their local regulators. It is ultimately a cost issue for loss of local load that does not
affect the overall reliability of the interconnected BES.

Alan Gale

City of Tallahassee

5

Affirmative

TAL thanks for SDT for the tireless effort to get to this point. TAL is voting affirmative with
the following comments. We accept that the loss of non-consequential load is not a desired
result for N-1 contingencies. It is also not the norm in system planning or operations. The
flexibility to operate the system consistent with “good utility practice” may warrant the
“odd-ball” case that would require this to occur. The dropping of non-consequential load

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
will NOT lead to BES instability, voltage collapse, or cascading outages, which is what FERC
and NERC are charged with preventing. It will lead to the shedding of load in a local area
only. Utilities do not drop customers lightly. If the meter isn’t turning, we are not getting
paid, so we want the meter spinning. Utility power, while vital to our normal day-to-day
lives and infrastructure, was never intended to be without interruption.

Brad Chase

Orlando Utilities
Commission

1

Affirmative

This change raises the bar on transmission system performance. This change applies a
blanket requirement upon entities that does not take into account the number of outages,
probability of outages or cost to the customer. There are certain to be situations where this
blanket requirement will result in increased cost to customers for no noticeable increase in
reliability. OUC does agree with the concept of greater clarification on this requirement,
however this clarification may raise the bar to far by trying to establish a blanket
requirement. Duke, Progress Energy and others will be submitting comments with
proposed language that attempt to address some of these issues and we encourage the
drafting team to consider those comments.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of

August 30, 2010

35

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Eric Egge

Black Hills Corp

1

Negative

Black Hills believes that the prohibition of loss of non-consequential load for events
resulting in the loss of a single element inappropriately reaches beyond the reliability of the
bulk power system to local load quality of service issues. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. NERC should be
allowed to hold a public technical conference, as described in NERC’s April 19, 2010,
request for rehearing before being required to develop and submit clarifications to footnote
b of Table 1.

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Negative

PG&E commends the SDT for developing the proposed footnote b. While it is a great
improvement over the complete prohibition on loss of non-consequential load for any single
contingency, the planned and controlled interruption of a small amount of load, under
certain conditions, is not a risk to reliability or an indication of an unreliable system, but
rather, serves to preserve the reliability of the bulk power system. Transmission Planners
and Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system, especially where the impact is local in nature, to avoid
instability, cascading or uncontrolled separation. Such planned interruption of load may be
a reasonable alternative to the environmental impacts or prohibitive costs associated with a
major new transmission project. Given the potential impacts of the proposed modification,
further vetting of the issues is needed. PG&E believes that NERC should be allowed to hold
a public technical conference, as described in NERC’s April 19, 2010, request for rehearing
before being required to develop and submit clarifications to footnote b of Table 1.

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
RRI supports the WECC position on this issue; namely, that the prohibition of loss of nonconsequential load for events resulting in the loss of a single element inappropriately
reaches beyond the reliability of the bulk power system to local load quality of service
issues. The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project. NERC should be allowed to hold a public technical conference, as
described in NERC’s April 19, 2010, request for rehearing before being required to develop
and submit clarifications to footnote b of Table 1.

Thomas J.
Bradish

RRI Energy

5

Negative

Trent
Carlson

RRI Energy

6

Negative

John Tolo

Tucson Electric
Power Co.

1

Negative

The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project.

James
Tucker

Deseret Power

1

Negative

The prohibition of loss of non-consequential load for events resulting the loss of a single
element inappropriately reaches beyond the reliability of the bulk power system to local
load quality of service issues. The planned and controlled interruption of a small amount of
load, under certain conditions, is not a risk to reliability or an indication of an unreliable
system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including

August 30, 2010

37

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

Louise
McCarren

Western Electricity
Coordinating
Council

10

Negative

The proposed revisions to footnote b of Table 1 are an improvement to the recently
balloted prohibition on loss of non-consequential load for single contingencies. The
recognition of the new term "temporarily radial" is a step in the right direction. However,
the planned and controlled interruption of a small amount of load, under certain conditions,
is not a risk to reliability or an indication of an unreliable system, but rather, serves to
preserve the reliability of the bulk power system. Transmission Planners and Planning
Coordinators should be given the discretion to determine whether or not the planned and
controlled interruption of load is an appropriate system response to certain contingencies,
taking into consideration all factors, including customer and local regulator input, for their
individual system. Often times when planned load interruption is identified as a response to
a single event, the impact to the system is local in nature. The planned interruption of load
may be the alternative to prohibitive costs associated with a major new transmission
project. NERC should be allowed to hold a public technical conference, as described in
NERC’s April 19, 2010, request for rehearing before being required to develop and submit
clarifications to footnote b of Table 1.

William
Mitchell
Chamberlain

California Energy
Commission

9

Negative

While the proposed revisions to footnote b are an improvement to the prohibition on loss of
non-consequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, the prohibition of loss of non-consequential load for events resulting the loss of a
single element still inappropriately reaches beyond the reliability of the bulk power system
to local load quality of service issues. The planned and controlled interruption of a small
amount of load, under certain conditions, is not a risk to reliability or an indication of an
unreliable system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is

August 30, 2010

38

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

John Mick

Colorado Springs
Utilities

6

Negative

Colorado Springs Utilities ballot on the proposed changes to TPL Table 1, footnote b
directed in FERC Order RM06-16-009 Colorado Springs Utilities wishes to vote NO on the
proposed changes to TPL Table 1, footnote b, directed in FERC Order RM06-16-009. CSU
concurs with the WECC position paper for the ballot, and agrees with the WECC statement
“that the prohibition of loss of non-consequential load for events resulting in the loss of a
single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues”.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.
The SDT agreed that a technical conference on this issue would be of value and held such a conference on August 10, 2010.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and

August 30, 2010

39

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Horace
Stephen
Williamson

Southern Company
Services, Inc.

1

Negative

Richard J.
Mandes

Alabama Power
Company

3

Negative

Anthony L
Wilson

Georgia Power
Company

3

Negative

Gwen S
Frazier

Gulf Power
Company

3

Negative

Don Horsley

Mississippi Power

3

Negative

Michael
Ibold

Xcel Energy, Inc.

3

Negative

Liam
Noailles

Xcel Energy, Inc.

5

Negative

David F.
Lemmons

Xcel Energy, Inc.

6

Negative

August 30, 2010

Comments have already been submitted previously, but it will be added here again.
Proposed footnote should read... No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial
Transmission Facilities. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power transfers when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch. It must be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected. The proposed changes are based on the
following... “The proposed wording by the drafting team seems to imply that the
curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language
stated only that curtailments were permitted to prepare for the next contingency, not to
address loading related to the initial contingency. The proposed wording could be
interpreted to allow redispatch/firm curtailments to address any single contingency
constraint. Southern Companies recommend that the original language relating to
“preparing for the next contingency” be incorporated into the drafting team’s proposal.”
The proposed modification to footnote b of Table I in TPL-001 - 004 standards states that
after a Category B contingency, there should not be any thermal, voltage or stability
violation, no interruption of firm load (except the load that is directly connected to the
elements that are removed from service as a result of the contingency) and no firm
transfer curtailment (except when coupled with re-dispatch of resources obligated to redispatch). We believe the proposed footnote b creates a gap between TPL-002 and TPL003 standards, since it does not address conditions when firm load shedding and firm
transfer curtailments are not required to meet the system performance for Category B
contingency, but one or both are the required system adjustments to prepare for the next
contingency (Category C3). When firm transfer is curtailed after the first contingency in

40

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
preparation for the next contingency, it is not clear from the proposed footnote b if this is
considered a valid system adjustment for Category C or a violation of Category B. Recall
that the existing footnote b addresses this condition explicitly by stating “To prepare for the
next contingency, system adjustments are permitted, including curtailments of contracted
Firm Transfers.”

George T.
Ballew

Tennessee Valley
Authority

5

Affirmative

Marjorie S.
Parsons

Tennessee Valley
Authority

6

Affirmative

Larry Akens

Tennessee Valley
Authority

1

Affirmative

TVA appreciates the work of the SDT on this issue. However, TVA recommends revising the
second paragraph of the revised footnote b: “To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers. However, curtailment of Firm Transmission Service is
only allowed when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected.” Without the changes in the first two
sentences above, the proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to address any single contingency constraint instead of in
preparation for the next contingency.
TVA appreciates the work of the SDT. However, TVA recommends revising the second
paragraph of the revised footnote "b". Without changes in the first two sentences, the
proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to
address any single contingency constraint instead of in preparation for the next
contingency.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address
loading issues that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings,
not to bring the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities
may utilize ratings in the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT
does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd
paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.

August 30, 2010

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Robert W.
Roddy

Dairyland Power
Coop.

1

Negative

DPC CONCURS WITH THE MRO COMMENTS.

Jason
Shaver

American
Transmission
Company, LLC

1

Affirmative

For Footnote b, add a third exception to the list, “or (3) end-use load that is either
accepted or volunteered by the customer". It is a widely-held understanding that the
tripping of non-consequential, end-use load is also allowed if the tripping of the load is
either accepted or volunteered by the customer.

Lawrence R.
Larson

Otter Tail Power
Company

1

Negative

The change precludes the use of direct load control systems that should be allowed to
relieve transmission problems. These systems control firm transmission load but rate
conditions can allow their use to mitigate transmission problems.

Response: (Note - MRO did not submit comments with the initial ballot – but did submit the following comment during the formal comment period: For
Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the customer". It is a widely-held
understanding that the tripping of non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered by the
customer in lieu of significant transmission system modifications. )

August 30, 2010

42

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

The SDT has modified the footnote to address your concern.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Ajay Garg

Michael D.
Penstone

Hydro One
Networks, Inc.

1

Hydro One
Networks, Inc.

3

August 30, 2010

Negative

Hydro One is casting a negative vote for the following reasons:
1. The amendment to the footnote does not add any technical value to the standard. It
was added only to satisfy a FERC directive to address comments made to allow nonconsequential load loss after a single contingency event, “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to
invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.”

Negative

2. Addressing curtailment of Firm Transmission Service with re-dispatch of resources is a
matter of a commercial nature and should be dealt with in the agreements dealing with
such services. Issues of contracted transmission services, firm or otherwise, are not a
reliability related matter and are not to be dealt with in this standard.

43

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

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Entity

Segment

Vote

Comment
3. Matters of interruption of firm load should be incorporated into this standard only after
the FERC NOPR on the definition of the BES is resolved. As it stands, the footnote will pose
significant problems if the 100 kV and above FERC proposal is applied across the board,
unless the standard specifically states that it applies to the BES as defined by the region
(current definition).

Response: 1. & 2. The SDT disagrees. The SDT believes that there could be a direct impact on reliability of the BES associated with uncontrolled
interruption of Demand and that it is important to discourage and limit the use of this option.The SDT has added clarity to the footnote.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
3. The SDT disagrees that this needs to wait on the FERC NOPR. This standard is applicable to the BES as it is defined.
Spencer
Tacke

Modesto Irrigation
District

August 30, 2010

4

Negative

I am voting NO vote because of the lack of clarity of the second paragraph of the proposed
change. Although paragraph 1 is an improvement to the current wording, and actually
allows for some specific flexibility in shedding load for an N-1 event, the lack of clarity in
the second paragraph could lead to varied interpretations by members and compliance

44

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
auditors. Thank you.

Response: The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Dana
Cabbell

Southern California
Edison Co.

1

Negative

David
Schiada

Southern California
Edison Co.

3

Negative

August 30, 2010

It is SCE’s position that the planned and controlled interruption of a small amount of load,
under certain conditions, is not a risk to reliability or an indication of an unreliable system,
but rather, serves to preserve the reliability of the bulk power system. Transmission
Planners and Planning Coordinators should be given the discretion to determine whether or
not the planned and controlled interruption of load is an appropriate system response to
certain contingencies, taking into consideration all factors, including customer and local

45

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Ahmad
Sanati

Entity
South California
Edison Company

Segment

Vote

5

Negative

Comment
regulator input, for their individual system. When planned load interruption is identified as
a response to a single event, the impact to the system is often local in nature. The planned
interruption of load may be a desirable alternative to the prohibitive costs associated with a
major new transmission project.
If the NERC Standards Drafting Team decides to proceed with footnote B, as written, it
needs to ensure that Transmission Owners, Transmission Operators, and Transmission
Planners have enough time to both design and implement any mitigation plans necessary
to be compliant with the new language. In almost all cases the actual implementation of a
solution requiring new construction will be dependent on a number of different regulatory
agencies providing the necessary permits allowing for its construction. As such, NERC
needs to ensure that any time frame associated with compliance to the proposed language
be variable, and allow for extended implementation time frames based on system
conditions that may delay placing mitigation plans in service. An example of a reasonable
variable time frame to be compliant with the proposed language in footnote B would be to
start the clock 60 months from receiving the pertinent environmental permitting. In
California this could be the issuance of a Draft Environmental Impact Review pursuant to
the California Environmental Quality Act.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.
The SDT has added more latitude for the Transmission Planner with the modifications and believes that 60 months should be sufficient.

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the

August 30, 2010

46

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Henry ErnstJr

Duke Energy
Carolina

August 30, 2010

3

Negative

On the initial ballot of TPL-001-1 Duke Energy also voted “Negative”, primarily because
Duke believes that the requirement prohibiting loss of non-consequential load for P1, P2.1
and P3 events is an overreach by the standard into local load quality of service issues. We
also sought rehearing on the Commission’s March 18 Order Setting Deadline for
Compliance (Docket No. RM06-16), with respect to this and other issues. We believe that
FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of
a single contingency appears to extend beyond measures needed for “reliable operation” of
the bulk-power system to prevent “instability, uncontrolled separation or cascading
failures,” none of which occur when utilities implement a planned and orderly loss of nonconsequential load. Hence, the Commission’s directive to prohibit utilities from
incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that
are needed for “reliable operation” of the bulk-power system as defined under Section 215
of the Federal Power Act. Such directive constitutes an overreaching of the Commission’s
jurisdiction under Section 215 of the Federal Power Act into the jurisdiction of state
commissions which generally have responsibility for overseeing quality of service issues
applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version
of TPL-001-1, it still does not allow Transmission Planners to use appropriate discretion
regarding loss of non-consequential load. Transmission Planners, customers, and local
regulators should jointly control the decision making when BES reliability is not an issue.
Often, the events are extremely improbable and the consequences of these events are local
in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. With this “Negative” vote, Duke

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

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Entity

Segment

Vote

Comment
offers the following ideas on alternatives for the SDT to consider that will allow for
appropriate discretion and facilitate proper planning while allowing non-consequential load
loss (NCLL). The standard should allow for dropping of limited amounts of nonconsequential load in situations where it would be reasonable for a bounded time period
and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations
where the near term impact of load projections or implementation of nearby
transmission/generation projects will alleviate the necessity of an upgrade to meet N-1
conditions. Also, reliability of service to end-use customer is impacted by the entire system
from source to load. Where allowance for NCLL would not greatly impact individual end-use
customers’ level of reliability the transmission planner should consider its use. Normally
transmission system outages are a minor contributor to overall customer outage frequency
and duration. Instances where allowance for NCLL can be used to avoid projects without
greatly impacting a customer’s outage frequency and duration should be acceptable. Use of
reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be considered by the SDT for
determination of acceptable use of NCLL.

Luther E.
Fair

Gainesville
Regional Utilities

1

Affirmative

Even though I am voting in the affirmative, I agree that most of the comments offered by
Duke and Norther Indiana in their earlier statements have merit and should be considered.
Also, I believe that the use of reliability metrics should be considered by the SDT for
determination of acceptable use of NCLL.

Mace Hunter

Lakeland Electric

3

Negative

Reliability should consider the entire system from source to load. Where allowance for
NCLL would not greatly impact individual end-use customer’s level of reliability the
transmission planner should consider its use. Normally transmission system outages are a
minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to delay projects without greatly impacting a customer’s
outage frequency and duration should be acceptable.
Use of reliability metrics should also be considered by the SDT for determination of
acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
balance the various industry concerns while assuring BES reliability.

August 30, 2010

48

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Sammy
Roberts

Progress Energy
Carolinas

1

Negative

Lee
Schuster

Florida Power
Corporation

3

Negative

August 30, 2010

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect
to conditional allowance of curtailing Firm Transmission Service, which is addressed in the
second paragraph of the proposed new footnote (b). PE remains concerned, however, that
the first paragraph of the proposed new footnote (b) does not allow for curtailment of nonradial non-consequential load. The ability to curtail non-consequential load in the planning
horizon can be a useful tool to mitigate local area issues, and has not been detrimental to

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Sam Waters

Wayne
Lewis

Entity
Progress Energy
Carolinas

Progress Energy
Carolinas

Segment

Vote

3

Negative

5

Negative

Comment
the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly
at a localized self-contained level of the system, i.e. the distribution system(s) served by
the Transmission Owner. Prohibiting the curtailment of local load thus constitutes
regulating distribution feeder reliability rather than BES reliability. Events that could be
mitigated through the curtailment of local, non-radial non-consequential load are
infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the
proposed footnote (b) be considered: “No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, and/or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that Load must be interrupted to meet performance requirements only on those
now radial Transmission Facilities, and/or (3) Planned or controlled interruption of any
additional Load required to mitigate the post-contingency results, provided that the nonconsequential load being shed for the event is localized, and provided that the total load
shed for the event does not exceed 2% of the Planned system peak demand or 200 MW,
whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability. The SDT did not adopt a numerical limit as it believes that any single numerical value applied
on a ntion-wide basis was not equitable for all entities.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial

August 30, 2010

50

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Timothy
VanBlaricom

California ISO

2

Negative

The California ISO supports NERC’s request for a public technical conference to be held, as
described in NERC’s April 19, 2010 request for rehearing and motion for stay of the March
18 Order (RM06-16-009), to provide the opportunity to gain industry input and written
comments regarding the Commission’s TPL-002-0 directive for NERC to develop a
modification to the TPL-002-0 Table 1 footnote b.

Response: The SDT agreed that a technical conference would be of value and held such a conference on August 10, 2010.
Terry L.
Blackwell

Santee Cooper

1

Negative

Zack
Dusenbury

Santee Cooper

3

Negative

Suzanne
Ritter

Santee Cooper

6

Negative

August 30, 2010

The Commission’s directive to prohibit utilities from incorporating carefully controlled loss of
non-consequential load into their planning processes appears to extend the Commission’s
reach beyond its review of measures that are needed for “reliable operation” of the bulkpower system as defined under Section 215 of the Federal Power Act. Such directive
constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the
Federal Power Act into the jurisdiction of state commissions which generally have
responsibility for overseeing quality of service issues applicable to local load. Table B
footnote still does not allow Transmission Planners to use appropriate discretion regarding
loss of non-consequential load. Transmission Planners, and local customers should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. The Commission’s directive sets forth
an expectation that NERC is to implement standards that address all loss of load at costs
that may not be commensurate with bulk power system reliability, as statutorily defined,
which is fundamentally different from what the Reliability Standards were intended to do.

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

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Entity

Segment

Vote

Comment

Response: The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Kimberly J.
Jones

North Carolina
Utilities
Commission

9

Negative

The NC Utilities Commission is concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1, and as explained in draft footnote b,
is an inappropriate overreach into service issues that are more appropriately addressed by
state regulatory commissions. This requirement does not provide any benefit to reliability
of the bulk electric system and could undermine state efforts to balance reliability issues
with cost of service issues. The standard should continue to allow Transmission Planners to
use discretion regarding loss of non-consequential load, understanding that state
commissions are positioned to force electric utilities to address local service quality issues
on an expedited basis, should it be necessary and in the public interest.

Response: The SDT understands the concern but believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES. The SDT’s approach will leverage existing processes to document and vet the situation.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the

August 30, 2010

52

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
James L.
Jones

Southwest
Transmission
Cooperative, Inc.

1

Negative

THE PROPOSED INTERPRETATION WILL UNDERMINE THE INTERNATIONAL STANDARDS
SETTING PROCESS AND COULD RESULT IN DIFFERING INTERPRETATIONS OF
STANDARDS ON THE NORTH AMERICAN BULK-POWER SYSTEM.

Response: The SDT disagrees and believes that the footnote has been clarified appropriately within the standards development process.
Daryn
Barker

Louisville Gas and
Electric Co.

6

Negative

The revised footnote b on Table 1 imposes additional requirements on the responsible
entities. The footnote states: Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.
However, R1 states: The Planning Authority and Transmission Planner shall each
demonstrate through a valid assessment that its portion of the interconnected transmission
system is planned These statements address different and inconsistent scope. If the
change in scope was intended then a change should also be made to R1 to reconcile the
inconsistency.

Charlie
Martin

Louisville Gas and
Electric Co.

5

Negative

Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions should also be respected. However, R1 states: The
Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned These
statements address different and inconsistent scope. If the change in scope was intended
then a change should also be made to R1 to reconcile the inconsistency.

Response: The SDT agrees that your assessment is for your portion of the interconnected grid. However, when performance in one system is dependent
on generation dispatch in another system or vice versa, the SDT believes that one must ensure that the re-dispatch is feasible. The SDT does not believe
that this presents a conflict with Requirement R1.
John
Apperson

PacifiCorp

August 30, 2010

3

Negative

This proposal warrants a “no” vote due to the current uncertainty regarding the outcome of
the FERC TPL-002 NOPR issued by FERC on March 18, 2010. The impacts of the proposed
changes to footnote B cannot be assessed separately from the alternative interpretation of
TPL-002 proposed by FERC. The proper planning of a transmission system requires that all
performance requirements are known and understood. If only some of the requirements
are known and understood it is impossible to properly plan, study, assess, and operate the

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Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
transmission system.

Response: The current TPL-002 is in force and will remain so until the completion of the cited FERC NOPR. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.
Keith V.
Carman

Tri-State G & T
Association Inc.

1

Negative

Tri-State does believe that the new footnote is an improvement, but thinks there are still
some changes necessary. We believe that the word “only” should be removed from the
phrase “...where that Load must be interrupted to meet performance requirements only on
those now radial Transmission Facilities” because that discrimination was not required in
FERC Order RM-06-16-009. There may be times when facilities near the temporary radial
facilities might fall outside the limits set in reliability criteria but the situation is mitigated if
the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State
recommends changing it to "Curtailment of Firm Transmission Service is not allowed unless
it is coupled with curtailment-offsetting resources that are obligated to re-dispatch. Further,
the curtailment activities cannot result in the shedding of any Firm load or in violations of
Facility Ratings, either internal or external to the planning region."
We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of nonconsequential load in the event of a single contingency appears to extend beyond
measures needed for “reliable operation” of the bulk-power system to prevent “instability,
uncontrolled separation or cascading failures,” none of which occur when utilities
implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of nonconsequential load into their planning protocols appears to extend the Commission’s reach
beyond its review of measures that are needed for “reliable operation” of the bulk-power
system as defined under Section 215 of the Federal Power Act. Such directive constitutes
an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for
overseeing quality of service issues applicable to local load.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.

August 30, 2010

54

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
The SDT is not in position to comment on FERC’s authority.
Claudiu
Cadar

GDS Associates,
Inc.

1

Negative

We do not agree with the proposed changes due to several reasons. Although the
proposed change will directly influence the reliability standards and transmission system
performances, will also have an indirect impact on the economic side with respect to the
expansion of existing transmission system. We believe that FERC directive as stipulated in
Order 693 cannot constrict, nor impose certain actions outside of the reliability limits. We
believe that since these events are merely isolated and rarely enforced, the decision of
mandating a great financial effort as a consequence of the proposed changes would
certainly be counterbalanced by its feasibility when compare with the current cost of load
shedding. While the revised footnote b can be certainly considered an improvement from
the current version, however it still does not allow the joined entities involved to have
power over the decision making when BES reliability is not an issue.
We also believe that any mandatory changes implemented in the TPL standards under the

August 30, 2010

55

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
current scenario are not entirely feasible unless all other issues such as the definition of the
BES, Consequential / Non-consequential Load, BES Critical Element, etc gets resolve ahead.
The revision with respect to load shedding, specifically the portion about shedding loads on
newly radial facilities, does not match the version 1 TPL standard definition of
consequential load loss. To approve the proposed revision to footnote ‘b’ would create an
unnecessary discrepancy between the version 1 TPL standard under consideration and the
existing standards. We recognize that the Version 1 will replace Version 0, but since it
appears that the performance standard with respect to footnote ‘b’ is intended to be same
in the revised footnote and the Version 1 standard, it only makes sense that the revised
version 0 footnote ‘b’ match the consequential load loss definition contemplated in Version
1.
In the light of the above we suggest the Commission to approach different other solutions
and ideas for improving the current reliability of the transmission system without enforcing
decisions beyond its statutory scope. We advance an alternative to this matter meant to
balance the reliability of the transmission system and its indirect financial impact. Although
the solution that we offer would require an extended time for development and
implementation, however we urge NERC to consider it in its further approach. Our
alternative consists mainly in implementing an additional term such as “Critical Load” which
we have briefly figured that would consist in particular load necessary to be maintained in
service without interruption. Even though this new term would seemed to be at first related
with the quality of the service, however a joint association of transmission planners,
customers, regulatory entities as decision makers can simply individualize the load that
cannot be shed, as well as future transmission improvements that will be required to serve
this envisioned small amount of load rather than the entire load. In this way we will create
a reasonable balance in between the reliability of the transmission system and the cost to
maintain / improve this reliability.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When

August 30, 2010

56

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
The current TPL-002 is in force and will remain so for the forseeable future. This limited scope revision to footnote ‘b’ is to add clarity to what is in effect.
Project 2006-02 is under revision and the clarifications of footnote ‘b’ will be considered by the SDT for future revisions of TPL-001-2.
The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the various
industry concerns while assuring BES reliability.
Ronald D.
Schellberg

Idaho Power
Company

1

Negative

While the proposed revisions are an improvement to the prohibition on loss of nonconsequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, that the prohibition of loss of non-consequential load for events resulting the loss of
a single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues.
However, the removal of: "To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers." will require significant adjustments in either TRM or TTC reductions to be
compliant with this revised standard in the WECC Region. To construct additional
transmission facilities to maintain present day business could easily exceed 10 Billion
dollars throughout the WECC region. For example, the Pacific AC Intertie currently has a
TTC of 4800 MW spread across 3 500 kV transmission lines. With the loss of one
Transmission line, the Pacific AC intertie drops to 3200 MW. Removal of this sentence

August 30, 2010

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Entity

Segment

Vote

Comment
would require TP either to drop the Firm TTC of the Intertie to 3200, or include a TRM
reservation of at least 1600 MW. The TPs would not be able to say that a loss of 1600 MW
of import capacity would not result in curtailments of firm load. Just about all multi
transmission line paths in the WECC Region would suffer. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. In the case of long
interties between subregions of WECC, these interties have never been planned to operate
in this manner. Idaho Power recommends that the sentence permiting system adjustments
be reinserted into Footnote B.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
the various industry concerns while assuring BES reliability.
The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring
the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may
utilize ratings in the planning horizon that can only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity
is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm transfers cannot be curtailed. Therefore, the SDT
does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2nd
paragraph to provide additional clarity in response to your comment and those of others.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the

August 30, 2010

58

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Contingency, or
o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Francis J.
Halpin

Bonneville Power
Administration

5

Affirmative

For consistency, regarding the firm transfer issue, the term "Firm Transmission Service"
should be replaced with "Firm Transfers" in order to be consistent with the fourth column
of the existing Table 1 "Transmission System Standards - Normal and Emergency
Conditions".

Response: The SDT agrees and has made the change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application

August 30, 2010

59

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

is subject to review and acceptance in an open and transparent stakeholder process.
No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Kim Warren

Independent
Electricity System
Operator

2

Affirmative

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES
and Firm Demand and on the understanding that the NERC standards apply only to the BES
as defined in the NERC Glossary as follows: “As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with
neighbouring systems, and associated equipment, generally operated at voltages of 100 kV
or higher. Radial transmission facilities serving only load with one transmission source are
generally not included in this definition.” To be clear, our interpretation of the present
definition of BES is that it defers to each Regional Reliability Organization to define the
elements of the power system that are considered BES and, therefore in the NPCC Region,
"BES as defined by NERC" = "BPS as defined by NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
Jacquie
Smith

ReliabilityFirst
Corporation

10

Affirmative

If this revision is an urgent action, then the implementation timeframe should be shorter.
In the clarification paragraph below, I do not understand the first sentence. Are there
commas missing? What is the requirement and what is the exception?
Also, I question the validity of using “should” in the second sentence. If it is a requirement,
then it needs to be stated as a requirement. If it is a suggestion, then it does not belong in
the standard.
No curtailment of Firm Transmission Service is allowed except when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated
that Facilities remain within applicable Facility Ratings and those adjustments do not result
in the shedding of any firm Load. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.

Response: This was originally classified as an ‘urgent action’ revision to meet the FERC due date which was June 30, 2010, not because NERC had
classified the modification as urgent for reliability. Note that FERC modified the due date to March 31, 2011 - this allows several more months of

August 30, 2010

60

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

development time and the SAR was revised to indicate that the proposed modification to footnote ‘b’ is no longer an Urgent Action revision.
Commas have been added as appropriate and a re-wording was made which should make this clear.
‘Should’ has been replaced by ‘would’ to provide additional clarity.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
David H.
Boguslawski

Northeast Utilities

1

Affirmative

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can
be better defined as the proposed revision is subject to interpretation by the different
entities and regulatory agencies. Future conflicts can be minimized by further clarifying the
proposed revision.
Also, NU is concerned that this new modification does not specify the amount of
permissible load shed nor does it require the planning entity to minimize load shedding
under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.

August 30, 2010

61

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

. Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Donald S.
Watkins

Bonneville Power
Administration

1

Affirmative

Rebecca
Berdahl

Bonneville Power
Administration

3

Affirmative

Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with
"Firm Transfers" to be consistent with the fourth column of the existing Table 1
Transmission System Standards - Normal and Emergency Conditions.

Response: The SDT agrees and has made this change.
Footnote ‘b’ now reads:
No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.

August 30, 2010

62

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements. When
interruption of Demand is utilized within the planning process, such interruption is limited to:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now radial
Transmission FacilitiesDemand that does not adversely impact overall BES reliability when: where the circumstances
describing the use of such Demand interruption are documented, including alternatives evaluated; and where the application
is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and
those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the
Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.
Frank
Gaffney

Florida Municipal
Power Agency

4

Affirmative

David
Schumann

Florida Municipal
Power Agency

5

Affirmative

Please see FMPA comments submitted through the concurrent comment period for Project
2010-11

Response: Please see the response to FMPA comments above.
Carter B
Edge

SERC Reliability
Corporation

10

Affirmative

The footnote makes clearer when load can be dropped for planning purposes. By making
this footnote more specific, it supports reliability and helps stakeholders apply the TPL
standards.

Response: Thank you for your support.

August 30, 2010

63

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Timothy
Beyrle

Entity

Segment

Vote

Comment

4

Affirmative

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all
honesty, shedding load for local area impacts has nothing to do with BES reliability and
should not be under FERC jurisdiction under Section 215 of the Federal Power Act, but
rather State jurisdiction for quality of service issues. However, there is also the matter of
FERC jurisdiction over commercial matters and the opportunity to “game” the original
footnote by transmission providers by allowing firm load shedding to grant firm
transmission service for themselves, thereby avoiding or deferring transmission investment,
while at the same time denying or requiring others to build the same transmission avoided
in order to obtain transmission service. We can see how difficult it is from a drafting team’s
perspective in achieving a balanced position between these different matters. The drafting
team should be applauded for finding a reasonable position.

1

Affirmative

This issue is better handled within the development of the new TPL-001 standard.

City of New
Smyrna Beach
Utilities
Commission

Response: Thank you for your support.
Larry E Watt

Lakeland Electric

Response: The current TPL-002 is in force and will remain so until the completion of the TPL-001-2 effort. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.

August 30, 2010

64

Consideration of Comments on Project 2010-11: TPL Table 1 Order and
Comments Submitted with Initial Ballots
The Standards Committee thanks all commenters who submitted comments on the
proposed SAR for the TPL Table 1 Order. The SAR proposed changes to TPL Table 1 in
response to FERC’s Order RM06-16-009 which requires the ERO to clarify TPL-002-0, Table
1 - footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single contingency occurs on a transmission system by June 30, 2010. Table 1 is used in
TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be reflected
in all four of these TPL standards.
The SAR, implementation plan, and the clean and redline versions to the four TPL standards
were posted for a 40-day public comment period from April 15, 2010 through May 27, 2010.
Stakeholders were asked to provide feedback on the standards through a special electronic
comment form. There were 22 sets of comments, including comments from more than 80
different people from approximately 40 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.
The initial ballot for the proposed changes to the four TPL standards was conducted from
May 17-27, 2010. The comments submitted with initial ballots and the drafting team’s
responses to those comments are also contained in this report.
All comments submitted during the comment period and the initial ballot results are posted
on the following page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Based on stakeholder comments, the drafting team has made some additional changes to
Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes include
the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the
terminology used in the associated column heading of Table 1 – ‘Loss of Demand or
Curtailed Firm Transfers.’ For additional clarity, the team made the following terminology
changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

The following bullet was added to Footnote ‘b’ to provide the flexibility requested by
stakeholders with respect to interrupting Demand, but with appropriate constraints to
protect reliability. The >90% demand level was selected to ensure that the number of
hours with exposure to demand loss was not unlimited. A 90% demand level is a
reasonably stressed case for most systems and the number of hours when peak demands
are >90% is a small percentage of the time for most systems. A large percentage of the
transmission lines that directly serve distribution customers are 161 kV or lower voltages.
Ten percent (10%) of the loading on a high capacity 161 kV transmission line is
approximately 50 MW.
•

Planned or controlled interruption of Demand required to address postContingency performance issues that occur at Demand levels greater than 90%
of forecasted Peak Demand provided that the Demand being interrupted does not
exceed 50 MW

The following bullet was added to Footnote ‘b’ to clarify that it is acceptable to use
Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

The above changes will be noted to stakeholders before the initiation of the recirculation
ballot.
The revised Footnote ‘b’ is:

b) No interruption of projected customer Demand is allowed except:
o

Interruption of Demand that is directly served by the elements that are removed from
service as a result of the Contingency

o

Planned or controlled interruption of Demand supplied by Transmission Facilities
made temporarily radial as a result of the Contingency and where that Demand must
be interrupted to meet performance requirements only on those now radial
Transmission Facilities

o

Planned or controlled interruption of Demand required to address post-Contingency
performance issues that occur at Demand levels greater than 90% of forecasted Peak
Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Gerry Adamski, at 609-452-8060 or at [email protected]. In addition, there is a
NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Comments and Responses from Formal Comment Period:
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which required the ERO to
clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system by June 30, 2010. Do you agree with the proposed changes and if not, please provide specific
reasons for your disagreement. .............................................................................................................................. 9

2.

Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any regulatory function,
rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the conflict. ................................... 21

Comments and Responses from Initial Ballot:
3.

Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010 ..................................... 26

June 10, 2010

3

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Commenter

Organization

Industry Segment
1

1.

Group

Guy Zito
Additional Member

2

3

4

5

6

8

9

10

Northeast Power Coordinating Council

X

Additional Organization

Region

Segment Selection

1. Alan Adamson

New York State Reliability Council

NPCC

10

2. Greg Campoli

New York Independent System Operator

NPCC

2

3. Roger Champagne

Hydro-Quebec TransEnergie

NPCC

2

4. Kurtis Chong

Independent Electricity System Operator

NPCC

2

5. Sylvain Clermont

Hydro-Quebec TransEnergie

6. Chris de Graffenried

Consolidated Edison Co. of New York, Inc.

NPCC

1

7. Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

8. Ben Eng

New York Power Authority

NPCC

4

9. Brian Evans-Mongeon

Utility Services

NPCC

8

10. Mike Garton

Dominion Resources Services, Inc.

NPCC

5

11. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

12. Kathleen Goodman

ISO - New England

NPCC

2

13. David Kiguel

Hydro One Networks Inc.

NPCC

1

14. Peter Yost

Consolidated Edison Co. of New York, Inc.

NPCC

3

June 10, 2010

7

1

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6

15. Randy MacDonald

New Brunswick System Operator

NPCC

2

16. Bruce Metruck

New York Power Authority

NPCC

6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18. Robert Pellegrini

The United Illuminating Company

NPCC

1

19. Saurabh Saksena

National Grid

NPCC

1

20. Michael Schiavone

National Grid

NPCC

1

2.

South Carolina Electric & Gas

Group

Philip R. Kleckley
Additional Member

X

Additional Organization

X
Region

Southern Company Services - Trans.

SERC

1

Tennessee Valley Authority

SERC

1

3. Charles Long

Entergy

SERC

1

4. James Manning

North Carolina Electric Membership Corporation

SERC

3

5. Pat Huntley

SERC Reliability Corporation

SERC

10

John Bee

Exelon Transmission Strategy & Compliance

Additional Member

X

Additional Organization

X
Region

Segment Selection

:(ComEd)

RFC

1

2. Weaver, David W

(PECO)

RFC

1

3. McHugh, Kathleen P

(PECO)

RFC

1

4. Kay, Thomas W

(ComEd)

RFC

1

5. Szymczak, Ronald

(ComEd)

RFC

1

6. Chu, Ron F

(PECO)

RFC

1

7. Donnelly, Michael J

(PECO)

RFC

1

8. Kliros, Chris B

(ComEd)

RFC

1

9. Mills, Paul M

(ComEd)

RFC

1

10. Webb, Becky

(ComEd)

RFC

1

Group

Denise Koehn

June 10, 2010

BPA, Transmission Reliability Program

X

X

10

X

1. Mortenson, Eric

4.

9

Segment Selection

2. David Marler

Group

8

X

1. Bob Jones

3.

7

X

X

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

Additional Member

2

Additional Organization

3

4

5

6

Region

BPA, Transmission Planning

WECC

1

2. Berhanu Tesema

BPA, Transmission Planning

WECC

1

3. Larry Furumasu

BPA, Transmission Planning

WECC

1

4. Kyle Kohne

BPA, Transmission Planning

WECC

1

5. Don Watkins

BPA, Transmission System Operations

WECC

1

6. Rebecca Berdahl

BPA, Power, Long Term Sales and Purchases

WECC

3

Group

Carol Gerou
Additional Member

Additional Organization

Region

Segment Selection

MRO

1

2. Tom Webb

Wisconsin Public Service

MRO

3, 4, 5, 6

3. Terry Bilke

Midwest ISO Inc.

MRO

2

4. Jodi Jenson

Western Area Power Administration

MRO

1, 6

5. Ken Goldsmith

Alliant Energy

MRO

4

6. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

7. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

8. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

9. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

10. Scott Nickels

Rochester Public Utilities

MRO

4

11. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

Richard Kafka

Pepco Holdings, Inc.

Additional Member

X

X

Additional Organization

X

X

Region

Segment Selection

1. Jim Summers

Delmarva Power and Light Co.

RFC

1

2. John Radman

Potomac Electric Power Company

RFC

1

7.

Group

Ben Li
Additional Member

June 10, 2010

10

X

American Transmission Company

Group

9

Midwest Reliability Organization

1. Chuck Lawrence

6.

8

Segment Selection

1. Chuck Matthews

5.

7

IESO

X
Additional Organization

Region

Segment Selection

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

1. Bill Phillips

MISO

MRO

2. James Castle

NYISO

NPCC

3. Charles Yeung

SPP

SPP

4. Lourdes Estrada-Salinero

CAISO

WECC

5. Patrick Brown

PJM

RFC

6. Steve Myers

ERCOT

ERCOT

8.

Group

Frank Gaffney

Florida Municipal Power Agency

Additional Member

2

3

X

Additional Organization

4

5

6

X

X

X

Region

Utilities Commission of New Smyrna Beach

FRCC

4

2. Greg Woessner

Kissimmee Utility Authority

FRCC

1

3. Jim Howard

Lakeland Electric

FRCC

1

4. Lynne Mila

City of Clewiston

FRCC

3

5. Joe Stonecipher

Beaches Energy Services

FRCC

1

6. Cairo Vanegas

Fort Pierce Utility Authority

FRCC

4

Individual

Stephen Mizelle

Southern Company Transmission

X

Robert Casey

Georgia Transmission Corporation (Bulk
System Planning)

X

Individual
11.

Individual

Thad Ness

American Electric Power

X

X

X

X

12.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

13.

Individual

Martin Bauer

US Bureau of Reclamation

14.

Individual

Kirit Shah

Ameren

X

X

X

15.

Individual

Robert W. Roddy

Dairyland Power Cooperative

X

X

X

10.

June 10, 2010

8

9

10

Segment Selection

1. Timothy Beyrle

9.

7

X
X

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Commenter

Organization

Industry Segment
1

2

3

4

5

6
X

16.

Individual

Marty Berland

Progress Energy

X

X

X

17.

Individual

Michael R. Lombardi

Northeast Utilities

X

X

X

18.

Individual

Charles Lawrence

American Transmission Company

X

19.

Individual

Greg Rowland

Duke Energy

X

X

X

X

X

X

X

Bill Middaugh

Tri-State Generation and Transmission
Association, Inc.

X

Individual
21.

Individual

Roger Champagne

Hydro-Québec TransEnergie (HQT)

X

22.

Individual

Dan Rochester

Independent Electricity System Operator

20.

June 10, 2010

7

8

9

10

X

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Order RM-06-16-009 which
required the ERO to clarify TPL-002-0, Table 1 — footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system by June 30, 2010. Do you agree with the proposed
changes and if not, please provide specific reasons for your disagreement.
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made
changes to the footnote to balance the various industry concerns while assuring BES reliability.
The 3rd bullet has been added to provide the flexibility requested by industry with appropriate constraints. This is limited by two conditions: >90%
demand level and 50 MW. The >90% demand level was selected to ensure that the number of hours with exposure to demand loss was not
unlimited. A 90% demand level is a reasonably stressed case for most systems and the number of hours when peak demands are >90% is a
small percentage of the time for most systems. A large percentage of the transmission lines that directly serve distribution customers are 161 kV
or lower voltages. Ten percent (10%) of the demand on a high capacity 161 kV transmission line is approximately 50 MW.
th

A 4 bullet has also been added to clarify that it is acceptable to use Interruptible demand and Demand-Side Management.
To match the terminology in the revised footnote with the terminology in the associated column heading (Loss of Demand or Curtailed Firm
Transfers) the term, ’Load’ was replaced with ‘Demand’ and the term ‘Firm Transmission Service’ was replaced with ‘firm transfers.’
Footnote ‘b’ now reads:

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Duke Energy

No

Duke Energy voted "Negative" on the initial and current ballots of TPL-001-1, primarily because Duke believes
that the requirement prohibiting loss of non-consequential load for P1, P2.1 and P3 events is an overreach by
the standard into local load quality of service issues. We also sought rehearing on the Commission’s March
18 Order Setting Deadline for Compliance (Docket No. RM06-16), with respect to this and other issues. We
believe that FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of a
single contingency appears to extend beyond measures needed for “reliable operation” of the bulk-power
system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many instances, it may be in the
best interest of all involved parties from an overall cost/benefit point of view to allow loss of non-consequential
load.
Duke offers the following ideas on alternatives for the SDT to consider that will allow for appropriate discretion
and facilitate proper planning while allowing non-consequential load loss (NCLL).The standard should allow
for dropping of limited amounts of non-consequential load in situations where it would be reasonable for a
bounded time period and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations where the near term
impact of load projections or implementation of nearby transmission/generation projects will alleviate the
necessity of an upgrade to meet N-1 conditions. Also, reliability of service to end-use customer is impacted by
the entire system from source to load. Where allowance for NCLL would not greatly impact individual enduse customers’ level of reliability the transmission planner should consider its use. Normally transmission
system outages are a minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to avoid projects without greatly impacting a customer’s outage frequency

June 10, 2010

10

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
and duration should be acceptable. Use of reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be
considered by the SDT for determination of acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
The SDT discussed the use of reliability metrics for providing flexibility to planners but has not included their use as this would make the implementation too
complex.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Midwest Reliability Organization

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant
transmission system modifications.

Dairyland Power Cooperative

No

DPC concurs with the MRO comments: For Footnote b, add a third exception to the list, "or (3) end-use load
that is either accepted or volunteered by the customer". It is a widely-held understanding that the tripping of
non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered
by the customer in lieu of significant transmission system modifications.

American Transmission
Company

No

For Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by
the customer". It is a widely-held understanding that the tripping of non-consequential, end-use load is also
allowed, if the tripping of the load is either accepted or volunteered by the customer in lieu of significant

June 10, 2010

11

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
transmission system modifications.

Response: The SDT has added the fourth bullet to address your concern.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Georgia Transmission
Corporation (Bulk System
Planning)

June 10, 2010

No

Georgia Transmission Corporation (GTC) believes that the requirement prohibiting loss of non-consequential
load for P1, P2.1 and P3 events is an overreach by the standard into local load quality of service issues. We
believe that FERC’s directive in (Docket No. RM06-16) to prohibit the loss of non-consequential load in the
event of a single contingency appears to extend beyond measures needed for “reliable operation” of the bulkpower system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur when
utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s directive
to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that are needed for
“reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act. Such
directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality of
service issues applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version of TPL-001-1, it still
does not allow Transmission Planners to use appropriate discretion regarding loss of non-consequential load.
Transmission Planners, customers, and local regulators should jointly control the decision making when BES
reliability is not an issue. Often, the events are extremely improbable and the consequences of these events
are local in nature, only requiring minor additional loss of local load to avoid the cost of major projects. In
many instances, it may be in the best interest of all involved parties from an overall cost/benefit point of view

12

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
to allow loss of non-consequential load.We also note that on April 19 NERC filed a request for rehearing with
FERC asking that the Commission revise the directive in Paragraph 8 of the March 18 TPL-002 Order to allow
NERC the necessary time to incorporate changes to the TPL-002 Reliability Standard through the Reliability
Standards Development Process that are necessary to achieve bulk power system reliability. NERC also
requested that the Commission grant NERC’s Motion for Stay to stay the Order so that a public technical
conference with opportunity for comment can be held in order to provide parties an opportunity to meet and
discuss the technical considerations of developing a modification to the TPL-002 standard that prohibits the
loss of non-consequential firm load in the event of an N-1 contingency. NERC’s April 19 filing pointed out that
if the Commission’s directive to disallow the loss of non-consequential firm load for an N-1 contingency is
implemented, a question is presented regarding whether the Reliability Standard still serves the purpose of
ensuring the Reliable Operation of the bulk power system by preventing instability, uncontrolled separation,
and cascading failures. That is, the Commission’s directive sets forth an expectation that NERC is to
implement standards that address all loss of load at costs that may not be commensurate with bulk power
system reliability, as statutorily defined, which is fundamentally different from what the Reliability Standards
were intended to do.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in
the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Progress Energy

June 10, 2010

No

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect to conditional
allowance of curtailing Firm Transmission Service, which is addressed in the second paragraph of the
proposed new footnote (b). PE remains concerned, however, that the first paragraph of the proposed new

13

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
footnote (b) does not allow for curtailment of non-radial non-consequential load. The ability to curtail nonconsequential load in the planning horizon can be a useful tool to mitigate local area issues, and has not been
detrimental to the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly at a localized selfcontained level of the system, i.e. the distribution system(s) served by the Transmission Owner/Operator.
Prohibiting the curtailment of local load thus constitutes regulating distribution feeder reliability rather than
BES reliability. Events that could be mitigated through the curtailment of local, non-radial non-consequential
load are infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the proposed footnote (b)
be considered:”No interruption of firm Load is allowed except: (1) Interruption of Load that is directly served
by the elements that are removed from service as a result of the Contingency, and/or (2) Planned or
controlled interruption of Load supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that Load must be interrupted to meet performance requirements only on those now
radial Transmission Facilities, and/or (3) Planned or controlled interruption of any additional Load required to
mitigate the post-contingency results, provided that the non-consequential load being shed for the event is
localized, and provided that the total load shed for the event does not exceed 2% of the Planned system peak
demand or 200 MW, whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate constraints.
The SDT did adopt a limit but felt that 2% of system peak or 200 MW was not equitable for all entities.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.

June 10, 2010

14

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization
Hydro-Québec TransEnergie
(HQT)

Yes or No

Question 1 Comment

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Northeast Power Coordinating
Council

No

The proposed changes do not adequately address FERC’s concerns in RM06-16-009. The Commission
again references Order 693 and specifically highlights comments by Duke Power Company and Northern
Indiana Public Service Company by saying the arguments made to date to allow non-consequential load loss
after a single contingency event is “based largely on the matter of economics, not reliability, with the
underlying premise that it is not economically feasible to invest in the bulk electric system to the point that it
can continue service to all firm load customers under some specific N-1 scenarios.” The proposed changes
to footnote ‘b’ indicate “No interruption of firm Load is allowed except:... (2) Planned or controlled interruption
of Load supplied by Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial Transmission
Facilities.” The exception described appears to still allow non-consequential load loss. FERC describes in
RM06-16-009 non-consequential load loss as “the removal, by any means, of any firm load that is not directly
served by the elements that are removed from service as a result of the contingency.” In referencing Order
693, the Commission reiterated its position that TPL standards “should not allow an entity to plan for the loss
of non-consequential load in the event of a single contingency.”
”Must” should be used instead of “should” in the last sentence of the footnote, making it to read “Facility
Ratings in those regions must also be respected.”

Response: The SDT believes that it has been responsive to the FERC directive in that the standards development process has been employed. In the

June 10, 2010

15

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

development of the footnote, the SDT has balanced the need for discretion while addressing local area concerns with the need to assure the reliability of the BES.
‘Must’ is not appropriate in a footnote as it would impose a requirement in the footnote. The SDT has replaced ‘should’ with ‘would’ to correct the grammar.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Tri-State Generation and
Transmission Association, Inc.

No

Tri-State does believe that the new footnote is an improvement, but thinks there are still some changes
necessary. We believe that the word “only” should be removed from the phrase “...where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities” because that
discrimination was not required in FERC Order RM-06-16-009. There may be times when facilities near the
temporary radial facilities might also fall outside the limits set in reliability criteria but the situation is mitigated
if the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State recommends changing it to
"Curtailment of Firm Transmission Service is not allowed unless it is coupled with curtailment-offsetting
resources that are obligated to re-dispatch. Further, the curtailment activities cannot result in the shedding of
any Firm load or in violations of Facility Ratings, either internal or external to the planning region."

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the
rd
various industry concerns while assuring BES reliability. Instead of removing the word ‘only’, the 3 bullet has been added to provide the flexibility requested by
industry with appropriate constraints.
The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.
b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

16

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Southern Company Transmission

No

We propose that the section in double parentheses be deleted. The proposed wording by the drafting team
seems to imply that the curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language stated only that
curtailments were permitted to prepare for the next contingency, not to address loading related to the initial
contingency. The proposed wording could be interpreted to allow redispatch/firm curtailments to address any
single contingency constraint.
Southern Companies recommend that the original language relating to “preparing for the next contingency” be
incorporated into the drafting team’s proposal.((Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted element or by the
affected area, may occur in certain areas without impacting the overall reliability of the interconnected
transmission systems. To prepare for the next contingency, system adjustments are permitted, including
curtailments of contracted Firm (non-recallable reserved) electric power Transfers.)) No interruption of firm
Load is allowed except: (1) Interruption of Load that is directly served by the elements that are removed from
service as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where that Load must be
interrupted to meet performance requirements only on those now radial Transmission Facilities. To prepare
for the next contingency, system adjustments are permitted, including curtailments of contracted Firm (nonrecallable reserved) electric power transfers No curtailment of Firm Transmission Service is allowed except
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch. where it can It must be
demonstrated that Facilities remain within applicable Facility Ratings and those adjustments do not result in
the shedding of any firm Load. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions should also be respected.

June 10, 2010

17

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the
Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in
the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an entity is obligated to redispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that
impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed. Therefore, the SDT does not believe that it is
nd
necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial changes to the 2 paragraph to provide additional
clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
South Carolina Electric & Gas

Yes

For better clarity delete the phrase “when coupled with” in the second paragraph of footnote ‘b.’

Response: The SDT did not delete the suggested phrase as it believes it is correct as stated but added commas to make the phrase read more clearly.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

June 10, 2010

18

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Independent Electricity System
Operator

Yes

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES and Firm Demand
and on the understanding that the NERC standards apply only to the BES as defined in the NERC Glossary
as follows:”As defined by the Regional Reliability Organization, the electrical generation resources,
transmission lines, interconnections with neighboring systems, and associated equipment, generally operated
at voltages of 100 kV or higher. Radial transmission facilities serving only load with one transmission source
are generally not included in this definition.” To be clear, our interpretation of the present definition of BES is
that it defers to each Regional Reliability Organization to define the elements of the power system that are
considered BES and, therefore in the NPCC Region, "BES as defined by NERC" = "BPS as defined by
NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
BPA, Transmission Reliability
Program

Yes

On the firm transfer issues, the term "Firm Transmission Service" should be replaced with "Firm Transfers" to
be consistent with the fourth column of the existing Table 1 Transmission System Standards - Normal and
Emergency Conditions.

Response: The SDT agrees and has made the change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

June 10, 2010

19

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No
o

Question 1 Comment

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
American Electric Power

Yes

Exelon Transmission Strategy &
Compliance

Yes

Florida Municipal Power Agency

Yes

IESO

Yes

Northeast Utilities

Yes

Pepco Holdings, Inc.

Yes

US Bureau of Reclamation

Yes

Manitoba Hydro

Yes

MH agrees with the SDT proposal.

Ameren

Yes

We were ok with the previous language. Though we do not intend to drop non-consequential load for a single
contingency, we undersatnd that other ares may have been following such practice without degarding the
relaibility of BES. We believe that they can continue this practice if they develop non-firm contracts with these
customers.

Response: Thank you for your support.

June 10, 2010

20

Consideration of Comments on TPL Table 1 Order — Project 2010-11

2. Are you aware of any conflicts caused by compliance with the proposed language in Table 1 — footnote b and any
regulatory function, rule order, tariff, rate schedule, legislative requirement or agreement? If yes, please identify the
conflict.
Summary Consideration: The SDT understands that there may be conflicts as pointed out by respondents; however, the SDT believes that
there should be constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustments the re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Organization

Yes or No

Ameren

No

American Electric Power

No

American Transmission
Company

No

BPA, Transmission Reliability

No

June 10, 2010

Question 2 Comment

21

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

Program
Dairyland Power Cooperative

No

Exelon Transmission Strategy &
Compliance

No

Independent Electricity System
Operator

No

Manitoba Hydro

No

Midwest Reliability Organization

No

Southern Company Transmission

No

US Bureau of Reclamation

No

South Carolina Electric & Gas

No

The comments expressed herein represent a consensus of the views of the above named members of the
SERC Engineering Committee Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board or its officers.

Hydro-Québec TransEnergie
(HQT)

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

Northeast Power Coordinating
Council

Yes

Conflicts may arise between individual state commissions, who may have rate recovery authority, and utilities
who attempt to abide explicitly with FERC’s position on non-consequential load loss. State commissions with
rate recovery authority may take the position that considering the economics of proposed investments
intended to prevent non-consequential loss of small or remote load is acceptable. This potential conflict
between state and federal positions could place utilities in a compromising position.

Response: Thank you for your response.

June 10, 2010

22

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

IESO

Yes

It should be noted that conflicts may arise between individual state commissions, who may have rate recovery
authority, and utilities who attempt to abide explicitly with FERC’s position on non-consequential load loss. In
RM-06-16-009, the Commission again references Order 693 and specifically highlights comments by Duke
Power Company and Northern Indiana Public Service Company by saying the arguments made to date to
allow non-consequential load loss after a single contingency event is “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to invest in the bulk
electric system to the point that it can continue service to all firm load customers under some specific N-1
scenarios.” In the US, State commissions with rate recovery authority may take the position that considering
the economics of proposed investments intended to prevent non-consequential loss of small or remote load is
acceptable. This potential conflict between state and federal positions could place utilities in a compromising
position.Similar conflicts may also exist in Canada.

Progress Energy

Yes

There is the potential for conflict between Table 1 - Footnote (b) as currently proposed, which can be
considered to regulate local distribution reliability without improving BES reliability, and local service reliability
issues which are under the purview of state regulatory agencies. For example, the North Carolina Utilities
Commission (NCUC) commented regarding this concern in the ballot which ended March 1 in Project 200602. Specifically, NCUC commented that they were “...concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1 is an inappropriate overreach into service issues that
are more appropriately addressed by state regulatory commissions...” Progress Energy believes that NCUC’s
concerns are legitimate. BES reliability should address the avoidance and mitigation of cascading outages
and BES facility damage, rather than limited, controlled local area loss of load, in order to avoid this conflict
and overlap of regulation.

Response: The SDT understands the issue; however, the SDT believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES.
Northeast Utilities

Yes

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can be better defined as
the proposed revision is subject to interpretation by the different entities and regulatory agencies. Future
conflicts can be minimized by further clarifying the proposed revision.
Also, NU is concerned that this new modification does not specify the amount of permissible load shed nor
does it require the planning entity to minimize load shedding under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
The SDT has modified the footnote for clarity and added constraints in new bullet 3 to address your specific concern.

June 10, 2010

23

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that LoadDemand must be interrupted to meet performance requirements only on those now radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels greater than
90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the re-dispatch does not result in the
shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions shouldwould also be respected.
Duke Energy

Yes

See response to question #1.

Georgia Transmission
Corporation (Bulk System
Planning)

Yes

See response to Question #1.

Response: See response to question #1.
Florida Municipal Power Agency

Yes

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all honesty, shedding load
for local area impacts has nothing to do with BES reliability and should not be under FERC jurisdiction under
Section 215 of the Federal Power Act, but rather State jurisdiction for quality of service issues. However,
there is also the matter of FERC jurisdiction over commercial matters and the opportunity to “game” the
original footnote by transmission providers by allowing firm load shedding to grant firm transmission service
for themselves, thereby avoiding or deferring transmission investment, while at the same time denying or
requiring others to build the same transmission avoided in order to obtain transmission service. We can see
how difficult it is from a drafting team’s perspective in achieving a balanced position between these different
matters. The drafting team should be applauded for finding a reasonable position.

Pepco Holdings, Inc.

Yes

This is not an issue for historic PJM members, but as PJM has expanded and as a result of the merger of
historic councils into RFC, I am aware that not all regions had standards equal to those of MAAC, and this

June 10, 2010

24

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 2 Comment
has been an issue worked out between transmission planners (historic transmission owners) and their local
regulators. It is ultimately a cost issue for loss of local load that does not affect the overall reliability of the
interconnected BES.

Response: Thank you for your support.
Tri-State Generation and
Transmission Association, Inc.

Yes

We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of non-consequential load
in the event of a single contingency appears to extend beyond measures needed for “reliable operation” of the
bulk-power system to prevent “instability, uncontrolled separation or cascading failures,” none of which occur
when utilities implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of non-consequential load into their
planning protocols appears to extend the Commission’s reach beyond its review of measures that are needed
for “reliable operation” of the bulk-power system as defined under Section 215 of the Federal Power Act.
Such directive constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the Federal
Power Act into the jurisdiction of state commissions which generally have responsibility for overseeing quality
of service issues applicable to local load.

Response: The SDT is not in a position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.

June 10, 2010

25

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

3. Consideration of Comments on Initial Ballot — TPL Table 1 Order (Project 2010-11) May 17–27, 2010
Summary Consideration: The SDT has listened to the comments from the industry, understands the concerns raised, and has made changes to
the footnote to balance the various industry concerns while assuring BES reliability.
The 3rd bullet has been added to provide the flexibility requested by industry with appropriate constraints. This is limited by two conditions: >90%
demand level and 50 MW. The >90% demand level was selected to ensure that the number of hours with exposure to demand loss was not
unlimited. A 90% demand level is a reasonably stressed case for most systems and the number of hours when peak demands are >90% is a
small percentage of the time for most systems. A large percentage of the transmission lines that directly serve distribution customers are 161 kV
or lower voltages. Ten percent (10%) of the demand on a high capacity 161 kV transmission line is approximately 50 MW.
th

A 4 bullet has also been added to clarify that it is acceptable to use Interruptible demand and Demand-Side Management.
The second paragraph of the footnote has been clarified and references Firm Transfers now instead of Firm Transmission Service.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the
Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result
of the Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now
radial Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand
levels greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those
adjustments the re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be respected.

Voter
Rodney
Phillips

Entity
Allegheny Power

June 10, 2010

Segment

Vote

Comment

1

Negative

Allegheny Power believes the loss of non-consequential load and/or curtailment of
transmission service for N-1 contingencies should be limited to only extreme circumstances.
Exception 2 of footnote b allows for the loss of non-consequential load for N-1

26

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
contingencies with no restriction. Allegheny Power recommends removing exception 2
footnote b.

Response: The SDT and the majority of the commenters disagree with this suggestion.
Gordon
Rawlings

BC Transmission
Corporation

1

Negative

Faramarz
Amjadi

BC Transmission
Corporation

2

Negative

Hubert C.
Young

South Carolina
Electric & Gas Co.

3

Negative

SCE&G has significant concern with the proposed revision to TPL Table 1, Footnote B. The
current Footnote B states “Planned or controlled interruption of electric supply to radial
customers or some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the
overall reliability of the interconnected transmission systems” is important to the TPL
standards to ensure that ERO standards do not dictate the level of service to customers.
Service to customers and load pockets is jurisdictional to State Commissions and ERO
standards should not compromise this jurisdiction. SCE&G believes that any proposed
revisions to Footnote B must retain the concept that planned or controlled interruption of
electric supply to customers, whether they are radial or network, is allowed as long as it
does not impact the overall reliability of the interconnected transmission systems. The
proposed revision eliminates this concept. There seems to be a general inconsistency and
maybe confusion between the terms “reliability” and “level of service”.

David Frank
Ronk

Consumers Energy

4

Negative

James B
Lewis

Consumers Energy

5

Negative

The current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the previous version of TPL-001-1. However, it still does
not allow Transmission Planners to use appropriate and necessary discretion regarding loss
of non-consequential load. Transmission Planners, customers, and local regulators should
control the decision making when BES reliability is not an issue. Often, the consequences of
these events are solely local in nature, requiring only minor additional loss of local load to

June 10, 2010

BCTC appreciates the good work of the SAR committee in drafting the changes to Footnote
b of Table 1. BCTC agrees with the drafting team that interruption of firm load, served by
either radial circuits or circuits that have became radial as a result of the contingency,
should be allowed for N-1 contingencies. However, it is our position that interruption of
firm load should not be limited only to such consequential loads. In our view, interruption
of electric supply to some local network customers in the affected area should be
permissible. This inclusion will allow transmission planners to plan BCTC’s regional
transmission network reliably and without impacting neighbouring transmission networks.

27

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
avoid the costly major projects. In many instances, it may be in the best interest of all
involved parties from an overall cost/benefit point of view to allow loss of nonconsequential load.

Hugh A.
Owen

Public Utility
District No. 1 of
Chelan County

6

Negative

The interruption of a small amount of load is, under most conditions, not a risk to the
reliability of the BES and is at times necessary to preserve reliability. The planned
interruption of some load may be a cost effective alternative to a costly transmission
project. That is a quality of service issue.

Michael
Gammon

Kansas City Power
& Light Co.

1

Negative

Charles
Locke

Kansas City Power
& Light Co.

3

Negative

Thomas
Saitta

Kansas City Power
& Light Co.

6

Negative

While the current revised footnote b is an improvement from the prohibition on loss of nonconsequential load associated with the recently balloted version of TPL-001-1, it still does
not allow Transmission Planners to use appropriate discretion regarding loss of nonconsequential load. Transmission Planners, customers, and local regulators should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load.

Linda Brown

San Diego Gas &
Electric

1

Affirmative

June 10, 2010

As to item (1), all load served directly by a transmission element which experiences a fault
will be interrupted when the faulted element is taken out of service. This is the natural
relationship between the load and the transmission element. Allowing this for BES elements
may encourage transmission owners to remove transmission instead of upgrading or
replacing it. Consider a load supplied by two transmission lines of different capacity. If the
larger line is lost due to a contingency (N-1) and the remaining smaller line overloads the
transmission owner is left with several options to address the problem: (1) move load
between buses, (2) upgrade the smaller line, (3) add another line, or (4) create a radial
load by removing the smaller line. Number (4) may be the least expensive and allowable
under TPL-002, footnote b. Item (2) may also encourage transmission owners to develop
plans which make load shedding part of category B. Consider a load served by three
transmission lines, a utility may decide to remove a line, instead of upgrading, in order to
set up a situation where an N-1 contingency would make the bus temporarily radial. In the
event of a single outage (N-1), the load bus will be temporarily radial and load can be shed
at the bus.

28

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

W. R.
Schoneck

Florida Power &
Light Co.

3

Affirmative

I believe the language is an improvement and clarifies the intent but I believe there still
should be additional language added to give an exemption in meeting this requirement if it
does not make economic sense(not economically feasible) and has no real impact on the
BES.

Richard J
Kafka

Potomac Electric
Power Co.

1

Affirmative

It is understood that this is a compliance filing issue. This is not an issue for historic PJM
members, but as PJM has expanded and as a result of the merger of historic councils into
RFC, I am aware that not all regions had standards equal to those of MAAC, and this has
been an issue worked out between transmission planners (historic transmission owners)
and their local regulators. It is ultimately a cost issue for loss of local load that does not
affect the overall reliability of the interconnected BES.

Alan Gale

City of Tallahassee

5

Affirmative

TAL thanks for SDT for the tireless effort to get to this point. TAL is voting affirmative with
the following comments. We accept that the loss of non-consequential load is not a desired
result for N-1 contingencies. It is also not the norm in system planning or operations. The
flexibility to operate the system consistent with “good utility practice” may warrant the
“odd-ball” case that would require this to occur. The dropping of non-consequential load
will NOT lead to BES instability, voltage collapse, or cascading outages, which is what FERC
and NERC are charged with preventing. It will lead to the shedding of load in a local area
only. Utilities do not drop customers lightly. If the meter isn’t turning, we are not getting
paid, so we want the meter spinning. Utility power, while vital to our normal day-to-day
lives and infrastructure, was never intended to be without interruption.

Brad Chase

Orlando Utilities
Commission

1

Affirmative

This change raises the bar on transmission system performance. This change applies a
blanket requirement upon entities that does not take into account the number of outages,
probability of outages or cost to the customer. There are certain to be situations where this
blanket requirement will result in increased cost to customers for no noticeable increase in
reliability. OUC does agree with the concept of greater clarification on this requirement,
however this clarification may raise the bar to far by trying to establish a blanket
requirement. Duke, Progress Energy and others will be submitting comments with
proposed language that attempt to address some of these issues and we encourage the
drafting team to consider those comments.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate

June 10, 2010

29

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

constraints.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Eric Egge

Black Hills Corp

June 10, 2010

1

Negative

Black Hills believes that the prohibition of loss of non-consequential load for events
resulting in the loss of a single element inappropriately reaches beyond the reliability of the
bulk power system to local load quality of service issues. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. NERC should be
allowed to hold a public technical conference, as described in NERC’s April 19, 2010,
request for rehearing before being required to develop and submit clarifications to footnote
b of Table 1.

30

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Negative

PG&E commends the SDT for developing the proposed footnote b. While it is a great
improvement over the complete prohibition on loss of non-consequential load for any single
contingency, the planned and controlled interruption of a small amount of load, under
certain conditions, is not a risk to reliability or an indication of an unreliable system, but
rather, serves to preserve the reliability of the bulk power system. Transmission Planners
and Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system, especially where the impact is local in nature, to avoid
instability, cascading or uncontrolled separation. Such planned interruption of load may be
a reasonable alternative to the environmental impacts or prohibitive costs associated with a
major new transmission project. Given the potential impacts of the proposed modification,
further vetting of the issues is needed. PG&E believes that NERC should be allowed to hold
a public technical conference, as described in NERC’s April 19, 2010, request for rehearing
before being required to develop and submit clarifications to footnote b of Table 1.

Thomas J.
Bradish

RRI Energy

5

Negative

Trent
Carlson

RRI Energy

6

Negative

RRI supports the WECC position on this issue; namely, that the prohibition of loss of nonconsequential load for events resulting in the loss of a single element inappropriately
reaches beyond the reliability of the bulk power system to local load quality of service
issues. The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project. NERC should be allowed to hold a public technical conference, as
described in NERC’s April 19, 2010, request for rehearing before being required to develop
and submit clarifications to footnote b of Table 1.

June 10, 2010

31

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

John Tolo

Tucson Electric
Power Co.

1

Negative

The planned and controlled interruption of a small amount of load, under certain
conditions, is not a risk to reliability or an indication of an unreliable system, but rather,
serves to preserve the reliability of the bulk power system. Transmission Planners and
Planning Coordinators should be given the discretion to determine whether or not the
planned and controlled interruption of load is an appropriate system response to certain
contingencies, taking into consideration all factors, including customer and local regulator
input, for their individual system. Often times when planned load interruption is identified
as a response to a single event, the impact to the system is local in nature. The planned
interruption of load may be the alternative to prohibitive costs associated with a major new
transmission project.

James
Tucker

Deseret Power

1

Negative

The prohibition of loss of non-consequential load for events resulting the loss of a single
element inappropriately reaches beyond the reliability of the bulk power system to local
load quality of service issues. The planned and controlled interruption of a small amount of
load, under certain conditions, is not a risk to reliability or an indication of an unreliable
system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

Louise
McCarren

Western Electricity
Coordinating
Council

10

Negative

The proposed revisions to footnote b of Table 1 are an improvement to the recently
balloted prohibition on loss of non-consequential load for single contingencies. The
recognition of the new term "temporarily radial" is a step in the right direction. However,
the planned and controlled interruption of a small amount of load, under certain conditions,
is not a risk to reliability or an indication of an unreliable system, but rather, serves to
preserve the reliability of the bulk power system. Transmission Planners and Planning
Coordinators should be given the discretion to determine whether or not the planned and
controlled interruption of load is an appropriate system response to certain contingencies,
taking into consideration all factors, including customer and local regulator input, for their

June 10, 2010

32

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
individual system. Often times when planned load interruption is identified as a response to
a single event, the impact to the system is local in nature. The planned interruption of load
may be the alternative to prohibitive costs associated with a major new transmission
project. NERC should be allowed to hold a public technical conference, as described in
NERC’s April 19, 2010, request for rehearing before being required to develop and submit
clarifications to footnote b of Table 1.

William
Mitchell
Chamberlain

California Energy
Commission

9

Negative

While the proposed revisions to footnote b are an improvement to the prohibition on loss of
non-consequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, the prohibition of loss of non-consequential load for events resulting the loss of a
single element still inappropriately reaches beyond the reliability of the bulk power system
to local load quality of service issues. The planned and controlled interruption of a small
amount of load, under certain conditions, is not a risk to reliability or an indication of an
unreliable system, but rather, serves to preserve the reliability of the bulk power system.
Transmission Planners and Planning Coordinators should be given the discretion to
determine whether or not the planned and controlled interruption of load is an appropriate
system response to certain contingencies, taking into consideration all factors, including
customer and local regulator input, for their individual system. Often times when planned
load interruption is identified as a response to a single event, the impact to the system is
local in nature. The planned interruption of load may be the alternative to prohibitive costs
associated with a major new transmission project. NERC should be allowed to hold a public
technical conference, as described in NERC’s April 19, 2010, request for rehearing before
being required to develop and submit clarifications to footnote b of Table 1.

John Mick

Colorado Springs
Utilities

6

Negative

Colorado Springs Utilities ballot on the proposed changes to TPL Table 1, footnote b
directed in FERC Order RM06-16-009 Colorado Springs Utilities wishes to vote NO on the
proposed changes to TPL Table 1, footnote b, directed in FERC Order RM06-16-009. CSU
concurs with the WECC position paper for the ballot, and agrees with the WECC statement
“that the prohibition of loss of non-consequential load for events resulting in the loss of a
single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues”.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.

June 10, 2010

33

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

The SDT agrees that a technical conference on this issue would be of value.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Horace
Stephen
Williamson

Southern Company
Services, Inc.

1

Negative

Richard J.
Mandes

Alabama Power
Company

3

Negative

Anthony L
Wilson

Georgia Power
Company

3

Negative

June 10, 2010

Comments have already been submitted previously, but it will be added here again.
Proposed footnote should read... No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, or (2) Planned or controlled interruption of Load supplied by
Transmission Facilities made temporarily radial as a result of the Contingency and where
that Load must be interrupted to meet performance requirements only on those now radial
Transmission Facilities. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power transfers when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch. It must be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions should also be respected. The proposed changes are based on the

34

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Gwen S
Frazier

Gulf Power
Company

3

Negative

Don Horsley

Mississippi Power

3

Negative

Michael
Ibold

Xcel Energy, Inc.

3

Negative

Liam
Noailles

Xcel Energy, Inc.

5

Negative

David F.
Lemmons

Xcel Energy, Inc.

6

Negative

George T.
Ballew

Tennessee Valley
Authority

5

Affirmative

Marjorie S.
Parsons

Tennessee Valley
Authority

6

Affirmative

June 10, 2010

Comment
following... “The proposed wording by the drafting team seems to imply that the
curtailment of firm transmission service is permitted to address single contingency
constraints if coupled with the redispatch of network resources. The original language
stated only that curtailments were permitted to prepare for the next contingency, not to
address loading related to the initial contingency. The proposed wording could be
interpreted to allow redispatch/firm curtailments to address any single contingency
constraint. Southern Companies recommend that the original language relating to
“preparing for the next contingency” be incorporated into the drafting team’s proposal.”

The proposed modification to footnote b of Table I in TPL-001 - 004 standards states that
after a Category B contingency, there should not be any thermal, voltage or stability
violation, no interruption of firm load (except the load that is directly connected to the
elements that are removed from service as a result of the contingency) and no firm
transfer curtailment (except when coupled with re-dispatch of resources obligated to redispatch). We believe the proposed footnote b creates a gap between TPL-002 and TPL003 standards, since it does not address conditions when firm load shedding and firm
transfer curtailments are not required to meet the system performance for Category B
contingency, but one or both are the required system adjustments to prepare for the next
contingency (Category C3). When firm transfer is curtailed after the first contingency in
preparation for the next contingency, it is not clear from the proposed footnote b if this is
considered a valid system adjustment for Category C or a violation of Category B. Recall
that the existing footnote b addresses this condition explicitly by stating “To prepare for the
next contingency, system adjustments are permitted, including curtailments of contracted
Firm Transfers.”
TVA appreciates the work of the SDT on this issue. However, TVA recommends revising the
second paragraph of the revised footnote b: “To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers. However, curtailment of Firm Transmission Service is
only allowed when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustments do not result in the shedding of any firm Load. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility

35

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
Ratings in those regions should also be respected.” Without the changes in the first two
sentences above, the proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to address any single contingency constraint instead of in
preparation for the next contingency.

Larry Akens

Tennessee Valley
Authority

1

Affirmative

TVA appreciates the work of the SDT. However, TVA recommends revising the second
paragraph of the revised footnote "b". Without changes in the first two sentences, the
proposed wording by the SDT could be interpreted to allow redispatch/firm curtailments to
address any single contingency constraint instead of in preparation for the next
contingency.

Response: The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address
loading issues that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings,
not to bring the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities
may utilize ratings in the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed.
Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made editorial
nd
changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

36

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Robert W.
Roddy

Dairyland Power
Coop.

1

Negative

DPC CONCURS WITH THE MRO COMMENTS.

Jason
Shaver

American
Transmission
Company, LLC

1

Affirmative

For Footnote b, add a third exception to the list, “or (3) end-use load that is either
accepted or volunteered by the customer". It is a widely-held understanding that the
tripping of non-consequential, end-use load is also allowed if the tripping of the load is
either accepted or volunteered by the customer.

Lawrence R.
Larson

Otter Tail Power
Company

1

Negative

The change precludes the use of direct load control systems that should be allowed to
relieve transmission problems. These systems control firm transmission load but rate
conditions can allow their use to mitigate transmission problems.

Response: (Note - MRO did not submit comments with the initial ballot – but did submit the following comment during the formal comment period: For
Footnote b, add a third exception to the list, "or (3) end-use load that is either accepted or volunteered by the customer". It is a widely-held
understanding that the tripping of non-consequential, end-use load is also allowed, if the tripping of the load is either accepted or volunteered by the
customer in lieu of significant transmission system modifications. )
The SDT has added the fourth bullet to address your concern.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

37

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Ajay Garg

Michael D.
Penstone

Entity

Segment

Vote

Hydro One
Networks, Inc.

1

Negative

Hydro One
Networks, Inc.

3

Comment
Hydro One is casting a negative vote for the following reasons:
1. The amendment to the footnote does not add any technical value to the standard. It
was added only to satisfy a FERC directive to address comments made to allow nonconsequential load loss after a single contingency event, “based largely on the matter of
economics, not reliability, with the underlying premise that it is not economically feasible to
invest in the bulk electric system to the point that it can continue service to all firm load
customers under some specific N-1 scenarios.”

Negative

2. Addressing curtailment of Firm Transmission Service with re-dispatch of resources is a
matter of a commercial nature and should be dealt with in the agreements dealing with
such services. Issues of contracted transmission services, firm or otherwise, are not a
reliability related matter and are not to be dealt with in this standard.
3. Matters of interruption of firm load should be incorporated into this standard only after
the FERC NOPR on the definition of the BES is resolved. As it stands, the footnote will pose
significant problems if the 100 kV and above FERC proposal is applied across the board,
unless the standard specifically states that it applies to the BES as defined by the region
(current definition).

Response: 1. & 2. The SDT disagrees – there is a direct impact on reliability of the BES associated with these concerns. The SDT has added clarity to the
footnote by designating constraints for Demand and firm transfer curtailment.
3. The SDT disagrees that this needs to wait on the FERC NOPR. This standard is applicable to the BES as it is defined.
Spencer
Tacke

Modesto Irrigation
District

4

Negative

I am voting NO vote because of the lack of clarity of the second paragraph of the proposed
change. Although paragraph 1 is an improvement to the current wording, and actually
allows for some specific flexibility in shedding load for an N-1 event, the lack of clarity in
the second paragraph could lead to varied interpretations by members and compliance
auditors. Thank you.

Response: The SDT made editorial changes to the 2nd paragraph to provide additional clarity in response to your comment and those of others.

b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

38

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Dana
Cabbell

Southern California
Edison Co.

1

Negative

David
Schiada

Southern California
Edison Co.

3

Negative

Ahmad
Sanati

South California
Edison Company

5

Negative

It is SCE’s position that the planned and controlled interruption of a small amount of load,
under certain conditions, is not a risk to reliability or an indication of an unreliable system,
but rather, serves to preserve the reliability of the bulk power system. Transmission
Planners and Planning Coordinators should be given the discretion to determine whether or
not the planned and controlled interruption of load is an appropriate system response to
certain contingencies, taking into consideration all factors, including customer and local
regulator input, for their individual system. When planned load interruption is identified as
a response to a single event, the impact to the system is often local in nature. The planned
interruption of load may be a desirable alternative to the prohibitive costs associated with a
major new transmission project.
If the NERC Standards Drafting Team decides to proceed with footnote B, as written, it
needs to ensure that Transmission Owners, Transmission Operators, and Transmission
Planners have enough time to both design and implement any mitigation plans necessary
to be compliant with the new language. In almost all cases the actual implementation of a
solution requiring new construction will be dependent on a number of different regulatory
agencies providing the necessary permits allowing for its construction. As such, NERC
needs to ensure that any time frame associated with compliance to the proposed language
be variable, and allow for extended implementation time frames based on system
conditions that may delay placing mitigation plans in service. An example of a reasonable
variable time frame to be compliant with the proposed language in footnote B would be to
start the clock 60 months from receiving the pertinent environmental permitting. In

June 10, 2010

39

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
California this could be the issuance of a Draft Environmental Impact Review pursuant to
the California Environmental Quality Act.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.
The SDT has added more latitude for the Transmission Planner with the addition of the 3rd bullet and believes that 60 months should be sufficient.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

40

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Henry ErnstJr

Entity
Duke Energy
Carolina

June 10, 2010

Segment

Vote

Comment

3

Negative

On the initial ballot of TPL-001-1 Duke Energy also voted “Negative”, primarily because
Duke believes that the requirement prohibiting loss of non-consequential load for P1, P2.1
and P3 events is an overreach by the standard into local load quality of service issues. We
also sought rehearing on the Commission’s March 18 Order Setting Deadline for
Compliance (Docket No. RM06-16), with respect to this and other issues. We believe that
FERC’s directive in that Order to prohibit the loss of non-consequential load in the event of
a single contingency appears to extend beyond measures needed for “reliable operation” of
the bulk-power system to prevent “instability, uncontrolled separation or cascading
failures,” none of which occur when utilities implement a planned and orderly loss of nonconsequential load. Hence, the Commission’s directive to prohibit utilities from
incorporating carefully controlled loss of non-consequential load into their planning
protocols appears to extend the Commission’s reach beyond its review of measures that
are needed for “reliable operation” of the bulk-power system as defined under Section 215
of the Federal Power Act. Such directive constitutes an overreaching of the Commission’s
jurisdiction under Section 215 of the Federal Power Act into the jurisdiction of state
commissions which generally have responsibility for overseeing quality of service issues
applicable to local load. While the current revised footnote b is an improvement from the
prohibition on loss of non-consequential load associated with the recently balloted version
of TPL-001-1, it still does not allow Transmission Planners to use appropriate discretion
regarding loss of non-consequential load. Transmission Planners, customers, and local
regulators should jointly control the decision making when BES reliability is not an issue.
Often, the events are extremely improbable and the consequences of these events are local
in nature, only requiring minor additional loss of local load to avoid the potential impacts
(environmental, historical, archaeological, aesthetic...) of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. With this “Negative” vote, Duke
offers the following ideas on alternatives for the SDT to consider that will allow for
appropriate discretion and facilitate proper planning while allowing non-consequential load
loss (NCLL). The standard should allow for dropping of limited amounts of nonconsequential load in situations where it would be reasonable for a bounded time period
and under restricted system conditions (e.g. 1-3 years only when load is >90 % of peak
conditions). Dropping of non-consequential load would be prudent planning in situations
where the near term impact of load projections or implementation of nearby
transmission/generation projects will alleviate the necessity of an upgrade to meet N-1
conditions. Also, reliability of service to end-use customer is impacted by the entire system

41

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
from source to load. Where allowance for NCLL would not greatly impact individual end-use
customers’ level of reliability the transmission planner should consider its use. Normally
transmission system outages are a minor contributor to overall customer outage frequency
and duration. Instances where allowance for NCLL can be used to avoid projects without
greatly impacting a customer’s outage frequency and duration should be acceptable. Use of
reliability metrics (e.g. SAIFI/SAIDI/ASAI) should also be considered by the SDT for
determination of acceptable use of NCLL.

Luther E.
Fair

Gainesville
Regional Utilities

1

Affirmative

Even though I am voting in the affirmative, I agree that most of the comments offered by
Duke and Norther Indiana in their earlier statements have merit and should be considered.
Also, I believe that the use of reliability metrics should be considered by the SDT for
determination of acceptable use of NCLL.

Mace Hunter

Lakeland Electric

3

Negative

Reliability should consider the entire system from source to load. Where allowance for
NCLL would not greatly impact individual end-use customer’s level of reliability the
transmission planner should consider its use. Normally transmission system outages are a
minor contributor to overall customer outage frequency and duration. Instances where
allowance for NCLL can be used to delay projects without greatly impacting a customer’s
outage frequency and duration should be acceptable.
Use of reliability metrics should also be considered by the SDT for determination of
acceptable use of NCLL.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to
rd
balance the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with
appropriate constraints.
The SDT discussed the use of reliability metrics for providing flexibility to planners but has not included their use as this would make the implementation
too complex.

b) No interruption of firm Load projected customer Demand is allowed except:

June 10, 2010

42

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Sammy
Roberts

Progress Energy
Carolinas

1

Negative

Lee
Schuster

Florida Power
Corporation

3

Negative

Sam Waters

Progress Energy
Carolinas

3

Negative

Wayne

Progress Energy

June 10, 2010

5

Negative

Progress Energy applauds NERC’s efforts to improve the footnote (b) language with respect
to conditional allowance of curtailing Firm Transmission Service, which is addressed in the
second paragraph of the proposed new footnote (b). PE remains concerned, however, that
the first paragraph of the proposed new footnote (b) does not allow for curtailment of nonradial non-consequential load. The ability to curtail non-consequential load in the planning
horizon can be a useful tool to mitigate local area issues, and has not been detrimental to
the Bulk Electric System (BES). Disallowing the curtailment of non-radial non-consequential
load essentially prohibits taking action in situations in which the load in question is clearly
at a localized self-contained level of the system, i.e. the distribution system(s) served by
the Transmission Owner. Prohibiting the curtailment of local load thus constitutes
regulating distribution feeder reliability rather than BES reliability. Events that could be
mitigated through the curtailment of local, non-radial non-consequential load are
infrequent, and such curtailment has no material effect on the reliability of the BES.
PE therefore suggests that the following addition (item (3)) to the first paragraph of the
proposed footnote (b) be considered: “No interruption of firm Load is allowed except: (1)
Interruption of Load that is directly served by the elements that are removed from service
as a result of the Contingency, and/or (2) Planned or controlled interruption of Load
supplied by Transmission Facilities made temporarily radial as a result of the Contingency
and where that Load must be interrupted to meet performance requirements only on those
now radial Transmission Facilities, and/or (3) Planned or controlled interruption of any
additional Load required to mitigate the post-contingency results, provided that the non-

43

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
Lewis

Entity

Segment

Vote

Carolinas

Comment
consequential load being shed for the event is localized, and provided that the total load
shed for the event does not exceed 2% of the Planned system peak demand or 200 MW,
whichever value is less.”

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints. The SDT did adopt a limit but felt that 2% of system peak or 200 MW was not equitable for all entities.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Timothy
VanBlaricom

California ISO

2

Negative

The California ISO supports NERC’s request for a public technical conference to be held, as
described in NERC’s April 19, 2010 request for rehearing and motion for stay of the March
18 Order (RM06-16-009), to provide the opportunity to gain industry input and written
comments regarding the Commission’s TPL-002-0 directive for NERC to develop a
modification to the TPL-002-0 Table 1 footnote b.

Response: The SDT agrees that a technical conference would be of value.

June 10, 2010

44

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
The Commission’s directive to prohibit utilities from incorporating carefully controlled loss of
non-consequential load into their planning processes appears to extend the Commission’s
reach beyond its review of measures that are needed for “reliable operation” of the bulkpower system as defined under Section 215 of the Federal Power Act. Such directive
constitutes an overreaching of the Commission’s jurisdiction under Section 215 of the
Federal Power Act into the jurisdiction of state commissions which generally have
responsibility for overseeing quality of service issues applicable to local load. Table B
footnote still does not allow Transmission Planners to use appropriate discretion regarding
loss of non-consequential load. Transmission Planners, and local customers should jointly
control the decision making when BES reliability is not an issue. Often, the events are
extremely improbable and the consequences of these events are local in nature, only
requiring minor additional loss of local load to avoid the cost of major projects. In many
instances, it may be in the best interest of all involved parties from an overall cost/benefit
point of view to allow loss of non-consequential load. The Commission’s directive sets forth
an expectation that NERC is to implement standards that address all loss of load at costs
that may not be commensurate with bulk power system reliability, as statutorily defined,
which is fundamentally different from what the Reliability Standards were intended to do.

Terry L.
Blackwell

Santee Cooper

1

Negative

Zack
Dusenbury

Santee Cooper

3

Negative

Suzanne
Ritter

Santee Cooper

6

Negative

Response: The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be
constraints on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Kimberly J.
Jones

North Carolina
Utilities
Commission

9

Negative

The NC Utilities Commission is concerned that the requirement prohibiting loss of nonconsequential load for events in Table 1 of TPL-001-1, and as explained in draft footnote b,
is an inappropriate overreach into service issues that are more appropriately addressed by
state regulatory commissions. This requirement does not provide any benefit to reliability
of the bulk electric system and could undermine state efforts to balance reliability issues
with cost of service issues. The standard should continue to allow Transmission Planners to
use discretion regarding loss of non-consequential load, understanding that state
commissions are positioned to force electric utilities to address local service quality issues
on an expedited basis, should it be necessary and in the public interest.

Response: The SDT understands the concern but believes that there should be constraints on the amount of Demand that can be tripped for single
Contingencies to assure the reliability of the BES.

June 10, 2010

45

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter
James L.
Jones

Entity
Southwest
Transmission
Cooperative, Inc.

Segment

Vote

1

Negative

Comment
THE PROPOSED INTERPRETATION WILL UNDERMINE THE INTERNATIONAL STANDARDS
SETTING PROCESS AND COULD RESULT IN DIFFERING INTERPRETATIONS OF
STANDARDS ON THE NORTH AMERICAN BULK-POWER SYSTEM.

Response: The SDT disagrees and believes that the footnote has been clarified appropriately within the standards development process.
Daryn
Barker

Louisville Gas and
Electric Co.

6

Negative

The revised footnote b on Table 1 imposes additional requirements on the responsible
entities. The footnote states: Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.
However, R1 states: The Planning Authority and Transmission Planner shall each
demonstrate through a valid assessment that its portion of the interconnected transmission
system is planned These statements address different and inconsistent scope. If the
change in scope was intended then a change should also be made to R1 to reconcile the
inconsistency.

Charlie
Martin

Louisville Gas and
Electric Co.

5

Negative

Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions should also be respected. However, R1 states: The
Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned These
statements address different and inconsistent scope. If the change in scope was intended
then a change should also be made to R1 to reconcile the inconsistency.

Response: The SDT agrees that your assessment is for your portion of the interconnected grid. However, when performance in one system is dependent
on generation dispatch in another system or vice versa, the SDT believes that one must ensure that the re-dispatch is feasible. The SDT does not believe
that this presents a conflict with Requirement R1.
John
Apperson

PacifiCorp

June 10, 2010

3

Negative

This proposal warrants a “no” vote due to the current uncertainty regarding the outcome of
the FERC TPL-002 NOPR issued by FERC on March 18, 2010. The impacts of the proposed
changes to footnote B cannot be assessed separately from the alternative interpretation of
TPL-002 proposed by FERC. The proper planning of a transmission system requires that all
performance requirements are known and understood. If only some of the requirements
are known and understood it is impossible to properly plan, study, assess, and operate the
transmission system.

46

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Response: The current TPL-002 is in force and will remain so until the completion of the cited FERC NOPR. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.
Keith V.
Carman

Tri-State G & T
Association Inc.

1

Negative

Tri-State does believe that the new footnote is an improvement, but thinks there are still
some changes necessary. We believe that the word “only” should be removed from the
phrase “...where that Load must be interrupted to meet performance requirements only on
those now radial Transmission Facilities” because that discrimination was not required in
FERC Order RM-06-16-009. There may be times when facilities near the temporary radial
facilities might fall outside the limits set in reliability criteria but the situation is mitigated if
the load shedding occurs at the radial facility.
The meaning of the second paragraph of the new footnote is unclear. Tri-State
recommends changing it to "Curtailment of Firm Transmission Service is not allowed unless
it is coupled with curtailment-offsetting resources that are obligated to re-dispatch. Further,
the curtailment activities cannot result in the shedding of any Firm load or in violations of
Facility Ratings, either internal or external to the planning region."
We believe that FERC’s directive in FERC Order RM-06-16-009 to prohibit the loss of nonconsequential load in the event of a single contingency appears to extend beyond
measures needed for “reliable operation” of the bulk-power system to prevent “instability,
uncontrolled separation or cascading failures,” none of which occur when utilities
implement a planned and orderly loss of non-consequential load. Hence, the Commission’s
directive to prohibit utilities from incorporating carefully controlled loss of nonconsequential load into their planning protocols appears to extend the Commission’s reach
beyond its review of measures that are needed for “reliable operation” of the bulk-power
system as defined under Section 215 of the Federal Power Act. Such directive constitutes
an overreaching of the Commission’s jurisdiction under Section 215 of the Federal Power
Act into the jurisdiction of state commissions which generally have responsibility for
overseeing quality of service issues applicable to local load.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. Instead of removing the word ‘only’, the 3 bullet has been added to provide the flexibility
requested by industry with appropriate constraints.
nd
The SDT made editorial changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.

June 10, 2010

47

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

The SDT is not in position to comment on FERC’s authority. The SDT understands the issue; however, the SDT believes that there should be constraints
on the amount of Demand that can be tripped for single Contingencies to assure the reliability of the BES.
Claudiu
Cadar

GDS Associates,
Inc.

1

Negative

We do not agree with the proposed changes due to several reasons. Although the
proposed change will directly influence the reliability standards and transmission system
performances, will also have an indirect impact on the economic side with respect to the
expansion of existing transmission system. We believe that FERC directive as stipulated in
Order 693 cannot constrict, nor impose certain actions outside of the reliability limits. We
believe that since these events are merely isolated and rarely enforced, the decision of
mandating a great financial effort as a consequence of the proposed changes would
certainly be counterbalanced by its feasibility when compare with the current cost of load
shedding. While the revised footnote b can be certainly considered an improvement from
the current version, however it still does not allow the joined entities involved to have
power over the decision making when BES reliability is not an issue.
We also believe that any mandatory changes implemented in the TPL standards under the
current scenario are not entirely feasible unless all other issues such as the definition of the

June 10, 2010

48

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
BES, Consequential / Non-consequential Load, BES Critical Element, etc gets resolve ahead.
The revision with respect to load shedding, specifically the portion about shedding loads on
newly radial facilities, does not match the version 1 TPL standard definition of
consequential load loss. To approve the proposed revision to footnote ‘b’ would create an
unnecessary discrepancy between the version 1 TPL standard under consideration and the
existing standards. We recognize that the Version 1 will replace Version 0, but since it
appears that the performance standard with respect to footnote ‘b’ is intended to be same
in the revised footnote and the Version 1 standard, it only makes sense that the revised
version 0 footnote ‘b’ match the consequential load loss definition contemplated in Version
1.
In the light of the above we suggest the Commission to approach different other solutions
and ideas for improving the current reliability of the transmission system without enforcing
decisions beyond its statutory scope. We advance an alternative to this matter meant to
balance the reliability of the transmission system and its indirect financial impact. Although
the solution that we offer would require an extended time for development and
implementation, however we urge NERC to consider it in its further approach. Our
alternative consists mainly in implementing an additional term such as “Critical Load” which
we have briefly figured that would consist in particular load necessary to be maintained in
service without interruption. Even though this new term would seemed to be at first related
with the quality of the service, however a joint association of transmission planners,
customers, regulatory entities as decision makers can simply individualize the load that
cannot be shed, as well as future transmission improvements that will be required to serve
this envisioned small amount of load rather than the entire load. In this way we will create
a reasonable balance in between the reliability of the transmission system and the cost to
maintain / improve this reliability.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

June 10, 2010

49

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

The current TPL-002 is in force and will remain so for the forseeable future. This limited scope revision to footnote ‘b’ is to add clarity to what is in effect.
Project 2006-02 is under revision and the clarifications of footnote ‘b’ will be considered by the SDT for future revisions of TPL-001-2.
The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance the various
industry concerns while assuring BES reliability.
Ronald D.
Schellberg

Idaho Power
Company

1

Negative

While the proposed revisions are an improvement to the prohibition on loss of nonconsequential load for a single contingency proposed in the recently failed TPL-001-1
ballot, that the prohibition of loss of non-consequential load for events resulting the loss of
a single element inappropriately reaches beyond the reliability of the bulk power system to
local load quality of service issues.
However, the removal of: "To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers." will require significant adjustments in either TRM or TTC reductions to be
compliant with this revised standard in the WECC Region. To construct additional
transmission facilities to maintain present day business could easily exceed 10 Billion
dollars throughout the WECC region. For example, the Pacific AC Intertie currently has a
TTC of 4800 MW spread across 3 500 kV transmission lines. With the loss of one
Transmission line, the Pacific AC intertie drops to 3200 MW. Removal of this sentence
would require TP either to drop the Firm TTC of the Intertie to 3200, or include a TRM
reservation of at least 1600 MW. The TPs would not be able to say that a loss of 1600 MW
of import capacity would not result in curtailments of firm load. Just about all multi

June 10, 2010

50

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
transmission line paths in the WECC Region would suffer. The planned and controlled
interruption of a small amount of load, under certain conditions, is not a risk to reliability or
an indication of an unreliable system, but rather, serves to preserve the reliability of the
bulk power system. Transmission Planners and Planning Coordinators should be given the
discretion to determine whether or not the planned and controlled interruption of load is an
appropriate system response to certain contingencies, taking into consideration all factors,
including customer and local regulator input, for their individual system. Often times when
planned load interruption is identified as a response to a single event, the impact to the
system is local in nature. The planned interruption of load may be the alternative to
prohibitive costs associated with a major new transmission project. In the case of long
interties between subregions of WECC, these interties have never been planned to operate
in this manner. Idaho Power recommends that the sentence permiting system adjustments
be reinserted into Footnote B.

Response: The SDT has listened to the comments from the industry, understands the concerns raised, and has made a change to the footnote to balance
rd
the various industry concerns while assuring BES reliability. The 3 bullet has been added to provide the flexibility requested by industry with appropriate
constraints.
The SDT believes that System re-dispatch is an acceptable System adjustment to “remain within applicable Facility Ratings” to address loading issues
that result from single Contingencies. As drafted, paragraph 2 of footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring
the Facilities within ratings. The draft language recognizes that System adjustments may be required after a single Contingency, since entities may
utilize ratings in the planning horizon that can be only be utilized for a limited time, such as a 2 hour emergency rating. Paragraph 2 clarifies that if an
entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan to re-dispatch those resources for a single Contingency.
However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the Firm Transmission Service cannot be curtailed.
Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the paragraph. The SDT made
nd
editorial changes to the 2 paragraph to provide additional clarity in response to your comment and those of others.
b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

June 10, 2010

51

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity
o

Segment

Vote

Comment

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Francis J.
Halpin

Bonneville Power
Administration

5

Affirmative

For consistency, regarding the firm transfer issue, the term "Firm Transmission Service"
should be replaced with "Firm Transfers" in order to be consistent with the fourth column
of the existing Table 1 "Transmission System Standards - Normal and Emergency
Conditions".

Response: The SDT agrees and has made the change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Kim Warren

Independent
Electricity System
Operator

June 10, 2010

2

Affirmative

IESO supports the revisions made to footnote ‘b’ based on the present definitions of BES
and Firm Demand and on the understanding that the NERC standards apply only to the BES
as defined in the NERC Glossary as follows: “As defined by the Regional Reliability
Organization, the electrical generation resources, transmission lines, interconnections with
neighbouring systems, and associated equipment, generally operated at voltages of 100 kV

52

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment
or higher. Radial transmission facilities serving only load with one transmission source are
generally not included in this definition.” To be clear, our interpretation of the present
definition of BES is that it defers to each Regional Reliability Organization to define the
elements of the power system that are considered BES and, therefore in the NPCC Region,
"BES as defined by NERC" = "BPS as defined by NPCC".

Response: The SDT agrees that the standard applies to the BES as defined in the Glossary.
Jacquie
Smith

ReliabilityFirst
Corporation

10

Affirmative

If this revision is an urgent action, then the implementation timeframe should be shorter.
In the clarification paragraph below, I do not understand the first sentence. Are there
commas missing? What is the requirement and what is the exception?
Also, I question the validity of using “should” in the second sentence. If it is a requirement,
then it needs to be stated as a requirement. If it is a suggestion, then it does not belong in
the standard.
No curtailment of Firm Transmission Service is allowed except when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated
that Facilities remain within applicable Facility Ratings and those adjustments do not result
in the shedding of any firm Load. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions should also be respected.

Response: This has not been classified as an ‘urgent action’.
Commas have been added as appropriate and a re-wording was made which should make this clear.
‘Should’ has been replaced by ‘would’ to provide additional clarity.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels

June 10, 2010

53

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW
o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
David H.
Boguslawski

Northeast Utilities

1

Affirmative

Northeast Utilities (NU) believes the language of the proposed revision to footnote ‘b’ can
be better defined as the proposed revision is subject to interpretation by the different
entities and regulatory agencies. Future conflicts can be minimized by further clarifying the
proposed revision.
Also, NU is concerned that this new modification does not specify the amount of
permissible load shed nor does it require the planning entity to minimize load shedding
under this exception.

Response: The SDT has made several clarifying changes to the footnote which should alleviate your concerns.
The SDT has modified the footnote for clarity and added constraints in new bullet 3 to address your specific concern.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.

June 10, 2010

54

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Donald S.
Watkins

Bonneville Power
Administration

1

Affirmative

Rebecca
Berdahl

Bonneville Power
Administration

3

Affirmative

Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

Comment
On the firm transfer issues, the term "Firm Transmission Service" should be replaced with
"Firm Transfers" to be consistent with the fourth column of the existing Table 1
Transmission System Standards - Normal and Emergency Conditions.

Response: The SDT agrees and has made this change.

b) No interruption of firm Load projected customer Demand is allowed except:
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a result of the Contingency, or

o

(2) Planned or controlled interruption of LoadDemand supplied by Transmission Facilities made temporarily radial as a result of the
Contingency and where that LoadDemand must be interrupted to meet performance requirements only on those now radial
Transmission Facilities.

o

Planned or controlled interruption of Demand required to address post-Contingency performance issues that occur at Demand levels
greater than 90% of forecasted Peak Demand provided that the Demand being interrupted does not exceed 50 MW

o

Interruptible Demand or Demand-Side Management

No cCurtailment of Firm Transmission Service firm transfers is allowed, except when coupled with the appropriate re-dispatch of resources
obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and those adjustments the redispatch does not result in the shedding of any firm LoadDemand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions shouldwould also be respected.
Frank
Gaffney

Florida Municipal
Power Agency

4

Affirmative

David
Schumann

Florida Municipal
Power Agency

5

Affirmative

June 10, 2010

Please see FMPA comments submitted through the concurrent comment period for Project
2010-11

55

Consideration of Comments on the Initial Ballot of TPL Table 1 Order — Project 2010-11

Voter

Entity

Segment

Vote

Comment

Response: Please see the response to FMPA comments above.
Carter B
Edge

SERC Reliability
Corporation

10

Affirmative

The footnote makes clearer when load can be dropped for planning purposes. By making
this footnote more specific, it supports reliability and helps stakeholders apply the TPL
standards.

Timothy
Beyrle

City of New
Smyrna Beach
Utilities
Commission

4

Affirmative

This is an area of fuzziness between State jurisdiction and Federal jurisdiction. In all
honesty, shedding load for local area impacts has nothing to do with BES reliability and
should not be under FERC jurisdiction under Section 215 of the Federal Power Act, but
rather State jurisdiction for quality of service issues. However, there is also the matter of
FERC jurisdiction over commercial matters and the opportunity to “game” the original
footnote by transmission providers by allowing firm load shedding to grant firm
transmission service for themselves, thereby avoiding or deferring transmission investment,
while at the same time denying or requiring others to build the same transmission avoided
in order to obtain transmission service. We can see how difficult it is from a drafting team’s
perspective in achieving a balanced position between these different matters. The drafting
team should be applauded for finding a reasonable position.

1

Affirmative

This issue is better handled within the development of the new TPL-001 standard.

Response: Thank you for your support.
Larry E Watt

Lakeland Electric

Response: The current TPL-002 is in force and will remain so until the completion of the TPL-001-2 effort. This limited scope revision to footnote ‘b’ is to
add clarity to what is in effect.

June 10, 2010

56

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-0.2: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-0c: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-0b: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-0a: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The effective date for footnote ‘b’ will be the first day of the first calendar quarter, 60 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, the effective date will be the first day of the first calendar quarter, 60 months after
Board of Trustees adoption.
All other requirements remain in effect as per previous approvals.
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

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R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
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D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is
discouraged and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance
requirements. When interruption of Demand is utilized within the planning process, such interruption is
limited to:

o

Demand that is directly served by the elements that are removed from service as a result of the
Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the circumstances describing
the use of such Demand interruption are documented, including alternatives evaluated; and where
the application is subject to review and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

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R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) No interruption of firm Load is allowed exceptAn objective of the planning process is to avoid interruption of
Demand. Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued
within the planning process. However, Demand may need to be interrupted in limited circumstances to address
BES performance requirements. When interruption of Demand is utilized within the planning process, such
interruption is limited to:

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from
service as a result of the Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet
performance requirements only on those now radial Transmission Facilities. FacilitiesDemand that
does not adversely impact overall BES reliability when: where the circumstances describing the use
of such Demand interruption are documented, including alternatives evaluated; and where the
application is subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate
re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within
applicable Facility Ratings and those adjustmentsthe re-dispatch does not result in the shedding of any firm
LoadDemand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions shouldwould also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.

Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Effe c tive Da te Dra ft 2: TBDAu g u s t 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

Draft 2: August 30, 2010

Page 1 of 13

S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Draft 2: August 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

Draft 2: August 30, 2010

Page 3 of 13

S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

Draft 2: August 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Draft 2: August 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 2: August 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is discouraged and
measures to mitigate such interruption should be pursued within the planning process. However, Demand may need to be
interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:
o

Demand that is directly served by the elements that are removed from service as a result of the
Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the circumstances describing
the use of such Demand interruption are documented, including alternatives evaluated; and where
the application is subject to review and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 2: August 30, 2010

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

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1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed except An objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance
requirements. When interruption of Demand is utilized within the planning process, such interruption is limited to::
o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from
service as a result of the Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made
temporarily radial as a result of the Contingency and where that Load must be interrupted to meet
performance requirements only on those now radial Transmission FacilitiesDemand that does not
adversely impact overall BES reliability when: where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is
subject to review and acceptance in an open and transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities
external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also
be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
Effective Date: TBDDraft 2: August 30, 2010

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f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBDDraft 2: August 30, 2010

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Effective Date: TBDDraft 2: August 30, 2010

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Effective Date: TBDDraft 2: August 30, 2010

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Effective Date: TBDDraft 2: August 30, 2010

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

Effective Date: TBDDraft 2: August 30, 2010

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Effective Date: TBDDraft 2: August 30, 2010

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1.

SAR submitted to SC in April 2010.

2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

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1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Draft 2: August 30, 2010

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 2: August 30, 2010

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is discouraged and
measures to mitigate such interruption should be pursued within the planning process. However, Demand may need to be
interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:

o

Demand that is directly served by the elements that are removed from service as a result of the Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the circumstances describing the use of
such Demand interruption are documented, including alternatives evaluated; and where the application is
subject to review and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1.

SAR submitted to SC in April 2010.

2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

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1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Effective Date: TBDDraft 2: August 30, 2010

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed exceptAn objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance
requirements. When interruption of Demand is utilized within the planning process, such interruption is limited to:

o

(1) Interruption of Load Demand that is directly served by the elements that are removed from service as a
result of the Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as
a result of the Contingency and where that Load must be interrupted to meet performance requirements only
on those now radial Transmission Facilities. FacilitiesDemand that does not adversely impact overall BES
reliability when: where the circumstances describing the use of such Demand interruption are documented,
including alternatives evaluated; and where the application is subject to review and acceptance in an open and
transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings
and those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also be
respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

Effective Date: TBDDraft 2: August 30, 2010

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBDDraft 2: August 30, 2010

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Effective Date: TBDDraft 2: August 30, 2010

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Effective Date: TBDDraft 2: August 30, 2010

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Effective Date: TBDDraft 2: August 30, 2010

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

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1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.

•

If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

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R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

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Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

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Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid interruption of Demand. Interruption of Demand is discouraged and
measures to mitigate such interruption should be pursued within the planning process. However, Demand may need to be
interrupted in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to:

o

Demand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the circumstances describing the use of
such Demand interruption are documented, including alternatives evaluated; and where the application is
subject to review and acceptance in an open and transparent stakeholder process.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
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f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:


The term ‘Load’ was replaced with ‘Demand’



The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events

1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:


Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.



Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.



If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.



A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events

In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:


Interruptible Demand or Demand-Side Management

Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

4. Recirculation ballot

January 2011

5. Submit to BOT for approval

January 2011

6. File with FERC

February 2011

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
None identified.

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-1 — System Performance Following Extreme BES Events
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Thermal and
Loss of Demand
Voltage
or
Cascading
Limits within
Outages
Curtailed Firm
Applicable
Transfers
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Effective Date: TBDDraft 2: August 30, 2010

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Standard TPL-004-0a — System Performance Following Extreme BES Events

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) No interruption of firm Load is allowed exceptAn objective of the planning process is to avoid interruption of Demand.
Interruption of Demand is discouraged and measures to mitigate such interruption should be pursued within the planning
process. However, Demand may need to be interrupted in limited circumstances to address BES performance
requirements. When interruption of Demand is utilized within the planning process, such interruption is limited to:

o

(1) Interruption of LoadDemand that is directly served by the elements that are removed from service as a
result of the Contingency, or

o

Interruptible Demand or Demand-Side Management

o

(2) Planned or controlled interruption of Load supplied by Transmission Facilities made temporarily radial as
a result of the Contingency and where that Load must be interrupted to meet performance requirements only
on those now radial Transmission Facilities. FacilitiesDemand that does not adversely impact overall BES
reliability when: where the circumstances describing the use of such Demand interruption are documented,
including alternatives evaluated; and where the application is subject to review and acceptance in an open and
transparent stakeholder process.

No cCurtailment of Ffirm Transmission Servicetransfers is allowed, except when coupled with the appropriate re-dispatch
of resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility
Ratings and those adjustmentsthe re-dispatch does not result in the shedding of any firm LoadDemand. Where Facilities
external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions shouldwould also
be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

Effective Date: TBDDraft 2: August 30, 2010

8 of 9

Standard TPL-004-0a — System Performance Following Extreme BES Events

e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Effective Date: TBDDraft 2: August 30, 2010

9 of 9

Comment Form for SAR and Footnote ‘b’ in Project 2010-11: TPL Table 1
Order
Please DO NOT use this form to submit comments on the 2nd posting for Project 2010-11:
TPL Table 1 Order. This comment form must be completed by October 8, 2010. This is a
30-day informal comment period. The drafting team will provide a summary response to
the one question asked on the comment form, but will not provide an individual response to
each comment submitted.
If you have questions please contact Ed Dobrowolski at [email protected] or by
telephone at 609-947-3673.

Background Information
Second Posting for Project 2010-11: TPL Table 1 Order
The 2nd posting is part of the continuing effort to address FERC Orders which required the
ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or controlled
interruption of electric supply where a single contingency occurs on a transmission system.
The 2nd posting is the result of the SDT review of the written comments received from
industry on the initial ballot and the inputs received from the Technical Conference of
August 10, 2010.
While the initial ballot results came close to the required approval percentage, it was clear
to the SDT from the cited inputs that there were still a number of concerns with the
proposed clarification. In particular, entities were concerned that the proposal was still
unclear and too limiting on the proposed conditions when load could be interrupted. Also,
there were numerous concerns raised on jurisdictional issues with regard to interrupting
demand. In short, the needed clarification hadn’t been achieved. Therefore, the SDT
continued discussions on different alternatives to address the needed clarification. This led
the SDT to focus on identifying constraining parameters such as the amount of demand that
could be interrupted, annual amount of exposure, etc.
In order to receive additional industry feedback on the new approach, a Technical
Conference was held on August 10, 2010 to address four specific questions arising from the
FERC June 11, 2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an entity to
plan to shed non-consequential firm load for a single contingency (Category B)? Please
provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be applied at the fringes of a system.
Is this limitation appropriate and if so, please define it? What other specific criteria
could be applied to limit the planned use of non-consequential firm load loss for a single
contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B), what
changes to your transmission plan would be required? Please quantify your response to
the extent possible.
4. The June 11th order from FERC suggested that planning to shed non-consequential firm
load for a single contingency (Category B) could be handled on a case-by-case basis
with affected entities asking for an exception from the ERO. Could you support such a
116-390 Village Boulevard, Princeton, New Jersey 08540-5721
Phone: 609.452.8060 ▪ Fax: 609.452.9550 ▪ www.nerc.com

Comment Form for 3rd Draft of Standard TPL-001-1
Assess Transmission Future Needs (Project 2006-02)
process? If your response is no, then what process would you suggest? If your
response is yes, then what technical criteria should be developed to identify and
evaluate cases?
In summary, the SDT heard that:
•

Industry feels that interrupting non-consequential load was appropriate in certain
limited circumstances and that such usage was not widespread.

•

Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’
could possibly be discriminatory.

•

If interruption of non-consequential load was not allowed, such a policy would result
in significant costs to customers for limited benefits.

•

A case-by-case exception process that required ERO or FERC approval was not
viewed as an acceptable approach due to possible inconsistencies in approach and
potential unacceptable delays.

The SDT took all of these inputs and returned to their deliberations attempting to leverage
the existing work with the industry comments to develop an acceptable clarification to
footnote ‘b’. This led to the approach shown in the 2nd posting where the SDT has taken the
concept of allowing interruption of demand without numerical constraints in an open and
transparent stakeholder process to review and accept such plans. This open and transparent
stakeholder process is seen as an enhancement of existing entity processes without the
problems associated with the ERO or FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693
directives (and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an
equal and effective method and that likely will be acceptable to all concerned parties.
The 2nd posting provides a revision to TPL Table 1 footnote ‘b’ to provide clarity to industry
with regard to the planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system. The referenced table appears in TPL-001,
TPL-002, TPL-003, and TPL-004 so while the FERC Order was for TPL-002, the change is
reflected in all 4 standards.

You do not have to answer all questions. Enter All Comments in Simple
Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC
Orders which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs
on a transmission system. Do you agree with the proposed changes and if not, please
provide specific reasons for your disagreement.
Yes
No
Comments:

Page 2 of 2

Standards Announcement
Informal Comment Period Open
September 8 - October 8, 2010
Now available at: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Project 2010-11 TPL Table 1 Order (Footnote ‘b’)
The TPL Table 1 Order Drafting Team is seeking comments on Table 1 footnote ‘b’ in TPL-001-1 through
TPL-004-1 until 8 p.m. EDT on October 8, 2010:
FERC Order RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1 - footnote ‘b,’ regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a transmission
system and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision
achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer considered “Urgent
Action.”
The drafting team developed a second draft of the proposed revision to TPL Table 1 footnote ‘b’ that reflects
consideration of the comments received from industry on the initial ballot and the inputs received from the
Technical Conference held on August 10, 2010. The second draft allows interruption of demand without
numerical constraints where the application is subject to review and acceptance in an open and transparent
stakeholder process.
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)
TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category B)
TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)
TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More Bulk
Electric System Elements (Category D)
Transition from Reliability Standards Development Procedure Version 7 – to Standard
Processes Manual
In accordance with the Standard Processes Manual approved by FERC on September 3, 2010, the drafting team
is using an “informal” comment period to solicit stakeholder feedback. The new standard development process
allows drafting teams to use informal comment periods. Unlike formal comment periods where a drafting team

provides a response to each comment submitted, with informal comment periods the drafting team provides a
summary response to each question asked on its comment form. The summary response will indicate whether
stakeholders support the proposal and will identify any additional changes made based on stakeholder
comments. With informal comment periods drafting teams are not required to provide an individual response to
each comment submitted – this change to the process is intended to give drafting teams more time to deliberate
on technical issues, as opposed to deliberating on individual responses to comments. Note that while informal
comment periods are allowed in the new standard process for preliminary drafts of proposed standards, formal
comment periods are still required for the final draft of each standard.
Instructions
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Next Steps
The drafting team will draft and post a summary response to the comments received and, if applicable, a revised
‘footnote b.’ After reviewing the comments, and determining whether there is a need for additional feedback on
the proposed footnote b language, the drafting team will determine its next steps. The next steps may include a
30-day formal comment period or may include a 45-day formal comment period with a ballot pool formed
during the first 30 days of that comment period and an initial ballot conducted during the last 10 days of the 45day comment period.
Project Background
The Assess Transmission Future Needs Standard Drafting Team (Project 2006-02) has developed a clarification
to TPL Table 1 — footnote ‘b’ concerning the loss of load and handling of firm transfers when a single
contingency occurs on the transmission system. Since this clarification may present a different interpretation of
footnote ‘b’ than the one presently used by some entities, the SDT is proposing a 60 month implementation plan
to allow those entities time to react.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,

Standards Program Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Individual or group. (43 Responses)
Name (32 Responses)
Organization (32 Responses)
Group Name (11 Responses)
Lead Contact (11 Responses)
Question 1 (43 Responses)
Question 1 Comments (43 Responses)
Group
Arizona Public Service Company
Jana Van Ness
Yes
Individual
Don Gilbert
JEA
No
The requirement in general is acceptable; however, there needs to be an added "such as" clause to the referenced
"...in an open and transparent stakeholder processes." I suggest adding "..."...in an open and transparent stakeholder
processes such as the FERC approved regional 890 process that includes the load serving entity affected".
Group
Northeast Power Coordinating Council
Guy Zito
No
1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of Demand that is
directly connected to the element that is removed from service. Recommend that the drafting team revise the wording
to eliminate this implication, and soften the expectation such that it is recognized that some Interruption of Demand is
unavoidable by system configuration, but that each entity should establish a reasonable limit on how much demand can
be interrupted due to the loss of an element. 2. The Statement that “However, Demand may need to be interrupted in
limited circumstances to address BES performance requirements” in the introductory paragraph contradicts bullet 3
“Demand that does not adversely affect BES …” 3. The third Bullet is confusing. Suggest revising the wording to clarify
the adverse impact to the BES system, documentation expectations, and to answer fundamental questions such as
who has the authority to decide the use if the stakeholder process is “accepting”, and the necessity of having a
stakeholder process. It is unlikely that the interruption of Demand will adversely impact the BES system. This constraint
is too broad. The language in this bullet also allows that non-consequential Demand interruption could be used to
mitigate reliability violations arising from the NERC Category B contingency events (i.e., single element contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified. 5. In the
last sentence of the second paragraph, “would” should be replaced by “must”. Alternatively, possible rewording of
footnote “b” to be considered: b) An objective of the planning process should be to minimize the likelihood of
interrupting Demand and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements or
other local reasons which have no adverse impact on overall BES reliability or the interconnected BES. When
interruption of Demand is utilized within the planning process, such interruption is limited to: o Demand that is directly
served by the elements that are removed from service as a result of the Contingency o Demand that does not
adversely impact overall reliability of the BES or the interconnected BES and where the circumstances describing the
use of such Demand interruption are documented, including alternatives evaluated; and where the application is
subject to review and acceptance in an open and transparent stakeholder process. Curtailment of firm transfers is
allowed, when coupled with the appropriate re-dispatch of available resources, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in
those regions would also be respected. The Drafting Team should reconsider the use of “Load” as opposed to
“Demand”. By definition (NERC Glossary dated April 20, 2010) Demand is: “1. The rate at which electric energy is
delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or
averaged over any designated interval of time. 2. The rate at which energy is being used by the customer.” Load is
defined as: “An end-use device or customer that receives power from the electric system.” This terminology is more
appropriate to the application used in the Table.
Group

SERC Planning Standards Subcommittee
Philip R. Kleckley
No
The revised text relating to the planning process exceeds what is appropriate for a reliability standard. Existing open
and transparent stakeholder processes focus on larger system issues and not on local load serving. We suggest the
following: Demand may need to be interrupted in limited circumstances to address BES performance requirements.
When interruption of Demand is utilized within the planning process, such interruption is limited to: o Demand that is
directly served by the elements that are removed from service as a result of the Contingency o Interruptible Demand or
Demand-Side Management o Demand that does not adversely impact overall BES reliability and is made temporarily
radial as a result of the Contingency, where that Demand must be interrupted to meet performance requirements.
Curtailment of firm transfers is allowed when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected. “The comments expressed herein represent
a consensus of the views of the above-named members of the SERC EC Planning Standards Subcommittee only and
should not be construed as the position of SERC Reliability Corporation, its board, or its officers.”
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
SCE&G believes the first sentence "An object of the planning process is to avoid interruption of Demand." goes beyond
what is appropriate for a reliability standard and therefore should be deleted. Also, the part of the sentence that states
"and where the application is subject to review and acceptance in an open and transparent stakeholder process" goes
beyond what is appropriate for a reliability standard and should be deleted.
Individual
Laura Zotter
ERCOT ISO
Yes
Group
PacifiCorp
Sandra Shaffer
No
PacifiCorp believes that the current version of footnote “b” is an improvement over the language that currently exists in
the standard, except for one component of the revised footnote. The third bullet in the draft standard currently limits the
interruption of Demand if it does not adversely impact overall BES reliability, where the circumstances describing the
use of the interruption are documented (including alternatives evaluated) and the application is subject to review and
acceptance in “an open and transparent stakeholder process.” PacifiCorp believes that the language requiring review
and acceptance of an application of demand interruption through any sort of stakeholder process should be removed. It
is not practical or effective to prescribe that either this standard or any other standard requires stakeholder approval in
order to maintain compliance. As presently drafted, this requirement for stakeholder review and acceptance appears to
be inconclusive and indeterminate as to what is required for registered entities to comply. Instead, this third bullet
should require the documentation, by the Planning Authority and Transmission Planner, of the circumstances
describing the use of Demand interruption – including methodologies used, assumptions relied upon, and alternatives
evaluated – as part of the Planning Authorities’ and/or Transmission Planners’ documentation of results in their annual
Reliability Assessments. These annual assessments are already submitted to the appropriate Regional Reliability
Organization pursuant to TPL-002-1b Requirement R3. This annual assessment can be provided by the ERO to other
appropriate third parties upon their request.
Individual
Greg Rowland
Duke Energy
Yes
Duke Energy strongly supports this revised footnote ‘b’. We believe that it provides for appropriate consideration of
stakeholder input in decision-making for local reliability issues, while maintaining the reliability of the Bulk Electric
System.
Individual
Steve Stafford
Georgia Transmission Corporation
Yes

Group
PPL Corp
John Cummings
Yes
PPL believes that Footnote b as described in TPL-002-1b, Draft 2, August 30, 2010 is fine provided an accompanying
Requirement (with appropriate VRF and VSL) and Measure is added to the TPL standard(s) to require and document
notification of the affected Demand parties and the involvement of the affected Demand parties in an open process as
described by Footnote b, third bullet.
Individual
John Canavan
NorthWestern Energy
No
In addition to the three bullet items, add a fourth bullet item to the list of limitations under the body of footnote b: “In no
case will a total loss of load that is less than 50 MW be considered a violation of this standard.”
Individual
Tim Ponseti
TVA Transmission Planning & Compliance
No
TVA supports FERC's actions on improving reliability of the BES; however, TVA believes that the new proposal is
focusing more on reliability of local loads than on the overall reliability of the BES. Footnote b should focus only on the
overall reliability of the BES. Reliability of local loads should be addressed outside the TPL standards and therefore
should not be used/referenced in footnote b. Also existing stakeholder processes (referred to in the SDT proposal)
typically focus on larger system issues and not on local load serving. Thus TVA believes that some local load should be
allowed to be dropped in order to maintain BES reliability. However TVA does believe that there should be a limit of
how much load can be dropped in order to maintain BES reliability. TVA believes that 50 MW is a reasonable number
for this limit. Based on the above, TVA proposes substituting the following for the revised footnote b: Demand may
need to be interrupted in limited circumstances to address BES performance requirements. When interruption of
Demand is utilized within the planning process, such interruption is limited to: Demand that is directly served by the
elements that are removed from service as a result of the Contingency Interruptible Demand or Demand-Side
Management Demand that does not adversely impact overall BES reliability, where that Demand (not to exceed 50
MW) must be interrupted to meet performance requirements. Curtailment of firm transfers is allowed when coupled with
the appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that Facilities remain
within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions
would also be respected.
Individual
Gordon Rawlings
BC Hydro
No
The SDT is to be commended for their efforts to develop clear, unambiguous language for Footnote “b”. From the
discussions that have taken place it seems that there are many different perspectives and to get agreement on specific
language will be very difficult. We believe that it would be useful to identify the main issues that Footnote “b” needs to
address and we consider those main issues to be: • Definitions of (a) Consequential Load Loss, (b) Firm Demand, (c)
Firm Transmission Capability (as distinct from the OATT term, “Firm Transmission Service”), (d) Firm Transfer (this
could be defined as transfers using the OATT’s Firm Transmission Service, (e) Manual System Adjustments
(capitalized in the Category C section of TPL-001, but not defined in the NERC Glossary) and (f) the Bulk Electric
System (BES). • Identifying permissible Demand/Transfer curtailment actions for (a) the planning studies simulating the
Category B event itself and (b) the planning studies associated with determining acceptable actions for preparing for
the next set of contingencies should the initial single contingency be prolonged (ie, last several weeks). This would
define the acceptable (pre-emptive) “Manual System Adjustments” of Category C events. • Define separate acceptable
curtailment actions for (a) curtailment of Demand (ie, end-user load) and (b) curtailment of market to market transfers,
that very rarely, if ever, result in the loss of any end-user load. • Define the planning studies required to determine the
acceptability of the impacts on the BES resulting from curtailments in a “remote” part of the system that have been
accepted by those directly affected by those curtailments. At this point we don’t have specific language to suggest, but
we do have the following comments that we hope will help: A. Interruption of Demand: A.1. Consider improving the
definition of “Firm Demand” in the NERC Glossary that now reads, “That portion of the Demand that a power supplier is
obligated to provide except when system reliability is threatened or during emergency conditions”. Perhaps it could be
changed to something like, “That portion of the Demand that the planned transmission system must be able to supply
without interruption for Category B events. A.2. Consider stating in Footnote “b” that curtailment of Firm Demand is (a)

not permitted in the simulation of the N-1 event itself and (b) it is not permitted as part of the (pre-emptive) “Manual
System Adjustments” needed to prepare for the next set of contingencies should the initial single contingency be
prolonged (ie, last several weeks). B. Interruption of Firm Transfers: B.1. “Firm Transfers” could be defined as transfers
using the OATT’s Firm Transmission Service, but consider developing a system reliability-based term for “Firm
Transmission Capability” instead of referring to the tariff-based NERC definition of “Firm Transmission Service”. This
would recognize the difference between planning standards and commercial/tariff rules. The NERC definition of “Firm
Transmission Service” is now, “The highest quality (priority) service offered to customers under a filed rate schedule
that anticipates no planned interruption”. Transmission tariffs address the priority of curtailments when the loading on a
transmission path needs to be reduced for whatever reason (single- or multiple-contingencies). The NERC
transmission planning standards need a system reliability definition like, “Firm Transmission Capability” is the
transmission capability across a cut-plane, on a defined transmission path or across a defined flowgate that is
available, before any manual corrective actions are taken, following the worst Category B event under the most
onerous normal system conditions considering all plausible generation dispatch patterns and the full range of expected
load levels.” B.2. Consider stating in Footnote “b” that curtailment of Firm Transfers is only permitted to the extent that
redispatch of generation can be implemented so that delivery to the Firm Transfer recipient is not interrupted (a) in the
planning studies of the Category B event itself and (b) as part of the (pre-emptive) “Manual System Adjustments”
needed to prepare for the next set of contingencies should the initial single contingency be prolonged (ie, last several
weeks). C. General Comments: C.1. Consider replacing the first bullet of the proposed Footnote “b” with simply
“Consequential Load Loss” since the NERC Project 2006 02 (TPL 001) Standard Drafting Team is introducing the
following definition: Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to isolate the fault
C.2. Consider removing “Demand-Side Management” (DSM) from the second bullet because that term is too general.
The present definition of DSM in the NERC Glossary is: “The term for all activities or programs undertaken by LoadServing Entity or its customers to influence the amount or timing of electricity they use”. C.3. Consider being more
specific on what constitutes acceptable “Interruptible Demand”, like: “Interruptible Demand that is part of an automatic
real-time Direct Control Load Management (DCLM) system that is activated by the contingencies that require it and that
is a completely “dual-redundant” scheme including all communications equipment. The DCLM system must result in
automatic curtailment of Demand that is fast enough to maintain all BES system performance standards (eg, voltage
stability, voltage dip, etc)”. C.4. Consider eliminating the description of how interrupting Demand that does not
adversely impact overall BES reliability was accepted (ie, the stakeholder process, etc). If such a process were
undertaken and it resulted in acceptance that the Demand could be curtailed for Category B events, wouldn’t that
simply mean that the Demand was “Interruptible Demand”. It really doesn’t matter what process resulted in it being
accepted. The key considerations are that (a) if the interruption of that Demand is necessary to maintain BES reliability,
then it must be interrupted in a very reliable manner (ie, dual redundant scheme, etc) and (b) if the interruption of that
Demand is not necessary to maintain the reliable performance of the BES, then that should be confirmed by the
planning studies (ie, it doesn’t need to have an expensive, sophisticated, dual-redundant DCLM scheme since the
impact on the BES is acceptable even if the scheme doesn’t work). D. Additional Questions related to Curtailment of
Firm Transfers: In the past, the latter part of Footnote B read: “To prepare for the next contingency, system
adjustments are permitted, including curtailments of contracted Firm (non-recallable reserved) electric power
Transfers.” The last part of the proposed Footnote B now reads: “Curtailment of firm transfers is allowed, when coupled
with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand.
Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions would also be respected.” We would like to understand the implications of the proposed Footnote B as it relates
to curtailment of Firm Transfers (as per definition proposed earlier) for the following questions: 1) In the most recent
draft of Footnote B, why was the NERC defined term ‘Firm Transmission Service’ replaced with the non-defined term
‘firm transfers’? 2) In the most recent draft of Footnote B, why was the tone softened from “No curtailment of Firm
Transmission Service is allowed, except…” to “Curtailment of firm transfers is allowed when…”? 3) Assuming an
outage of a single transmission line (N-1 Category B event) has occurred and assuming that no “resources [are]
obligated to redispatch” for this outage, would a transmission provider be allowed to curtail Firm Transmission Service
(NERC defined term) that it has sold in order to prepare to withstand the next worst credible contingency? 4) Would
transmission providers be allowed to sell Firm Transmission Service on a path above what could be delivered with any
one element of that path out of service and a range of operating conditions? 5) If the proposed Footnote B is approved,
would utilities have to reinforce their system (within 60 months) to ensure that Firm Transmission Service for particular
paths would not be curtailed can be delivered when any one element of that path is out of service? 6) If a transmission
provider employs Generation Dropping for single contingencies in order to support Firm Transmission Service between
regions, and assuming there are no provisions for obligated re-dispatch, would the proposed Footnote B force a
recalculation of firm vs non-firm transfer capability? 7) Path 66 (PACI) and Path 65 (PDCI) can both see significant
derates in their firm transfer capability for single contingencies. How would the proposed Footnote B impact Firm
Transmission on these paths?
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
No

The revised draft is a significant improvement over the first draft. However, we suggest the following minor changes: 1.
The criterion of “adversely affect overall BES reliability” is undefined and maybe subject to a wide range of
interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words “as
defined by each Transmission Planner or Planning Authority”. 2. The term of “firm transfers” is undefined and maybe
subject to a wide range of interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest
establishing a definition for the term, reverting to the “Firm Transmission Service” term, or using another appropriate
defined term.
Individual
Jon Kapitz
Xcel Energy
Yes
Xcel Energy supports the new interpretation that would allow curtailment of firm transfers or demand for limited
conditions where the integrity of bulk electric system is not compromised. However Xcel Energy seeks some
clarification regarding the following: The 3rd bullet point in footnote b will need to clarify whether the demand
interruption can be done after the contingency, or before the contingency. If it is allowed after the contingency, then the
standard would allow violation of voltage or thermal loading criteria for a brief period, after contingency and, before
demand curtailment happens. Is this acceptable based on the new interpretation? Since TPL-002 standard deals with
NERC Category B contingencies, and footnote b states that curtailment of firm transfers is allowed, it should be
clarified if this curtailment is allowed before or after the contingency. If the curtailment is allowed only after the
contingency, then the system would be in violation of the thermal or voltage criteria for a brief period till the generation
is re-dispatched. Is this allowed by the new interpretation? If curtailment is only allowed in preparation of the
contingency, then the firm transfers would be curtailed during system intact conditions, in preparation for the first
contingency, resulting in violation of TPL-001 standard. Is this allowed by the new interpretation?
Individual
John Sullivan
Ameren
No
The revised text to footnote b relating to the planning process exceeds what is appropriate for a reliability standard.
Existing open and transparent stakeholder processes focus on larger system issues rather than on local load serving
issues. We suggest the following text for footnote b: Demand may need to be interrupted in limited circumstances to
address BES performance requirements. When interruption of Demand is utilized within the planning process, such
interruption is limited to: o Demand that is directly served by the elements that are removed from service as a result of
the Contingency o Interruptible Demand or Demand-Side Management o Demand that does not adversely impact
overall BES reliability and is made temporarily radial as a result of the Contingency, where that Demand must be
interrupted to meet performance requirements. Curtailment of firm transfers is allowed when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within
applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities
external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be
respected.
Individual
Darcy O'Connell
California ISO
Yes
1) Regarding the 2nd bullet provision, we suggest: Interruptible Demand or Demand-Side Management that has been
reviewed and approved by the Planning Authority. 2) Regarding the 3rd bullet provision, we suggest: Demand
interruption that does not adversely impact overall BES reliability…. 3) Also regarding the 3rd bullet provision, we
suggest replacing acceptance with clarification to read “where the application is subject to review and clarification in an
open and transparent stakeholder process."
Individual
Doug Hohlbaugh
FirstEnergy
No
FirstEnergy appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable proposal
for clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also commend NERC staff
for convening an industry technical conference to discuss the topic and FERC staff for their participation in the
technical conference as the industry carefully considered various perspectives. The proposed footnote B is much
improved from the prior draft proposals. One change that FirstEnergy proposes is to strike the text following the
semicolon in the third bullet item which states “and where the application is subject to review and acceptance in an
open and transparent stakeholder process.” This text may be intended as explanatory but has the appearance of
mandating an approval process that will be auditable through the TPL reliability standards. The statement is not

needed within the framework of mandatory reliability requirements as FERC Order 890 already mandates an open and
transparent process related to the planning of the bulk electric system. FERC via the 890 Final Rule modified the pro
forma Open-Access Transmission Tariff to require open and transparent stakeholder process to better ensure no
undue discrimination and access to the transmission system. The Final Rule beginning at paragraph 418 discusses
reform to the Coordinated, Open and Transparent Planning of the transmission system. The Commission direction
included eight planning principles required to be within the open process – one of which is dispute resolution. It should
be well understood that the transmission planner and planning coordinator share and disseminate all of their planning
study results and proposed corrective actions – including the proposed use of Demand interruption – as part of their
adherence to Order 890. We appreciate the SDT’s careful consideration of our comments.
Individual
Orlando A Ciniglio
Idaho Power
Yes
footnote 'b' is silent with respect to planned removal from service of certain generators. I believe there are many
conditions out there where a single contingency can initiate a planned (RAS-initiated) removal of generation. The fact
that this is mentioned in footnote 'c', under multiple contingencies, begs the need for futher elaboration/discussion of
this option under single contingencies in footnote 'b'.
Individual
Michael Lombardi
Northeast Utilities
No
NU agrees with the language of the proposed revision to Footnote b EXCEPT FOR bullet #3 which suggests that nonconsequential demand interruption could be used to mitigate reliability violations arising from the NERC Category B
contingency events (i.e., single element contingencies).
Individual
Thad Ness
American Electric Power
Yes
Individual
JC Culberson
ERCOT
No
The introductory paragraph of footnote b includes policy language. Since this is a reliability standard—and not a policy
directive—the general narrative setting forth the desired policy goal of minimizing load-shedding is misplaced. Including
policy language can cloud the specific issues the standard attempts to address, and ERCOT recommends deleting the
first two sentences in the introductory paragraph. The next sentence in the introductory paragraph goes on to state,
generally, that demand may be interrupted to "address BES performance requirements.” This phrase is vague. To
which performance requirements does this refer? The intent is not clear. If the intent is to generally recognize the need
to shed load to respect NERC standards and to allow flexibility for an entity to exercise discretion relative to meeting
BES performance requirements, then that intent should be clearly reflected in the language. Furthermore, the last
sentence of the introductory paragraph and the subsequent bullet points are arguably inconsistent with this approach,
because they could be viewed as removing an entity’s flexibility/discretion by limiting the circumstances when load can
be shed. The second bullet point is unnecessary, because it is already apparent that interruptible demand/demand side
management programs can be used according to their terms. This could create confusion in that it could be implied
that, absent the need to use these to meet BES performance requirements, using them otherwise is inconsistent
with/not allowed under footnote b. Simply put, those products are not load shedding as contemplated by this footnote.
Therefore they should not be listed here. With respect to the third bullet point, the phrase "demand that does not
adversely impact overall BES reliability" is not adequately defined, and provides opportunity for confusion. This is an
ambiguous phrase and can’t be linked back to objective NERC standards/requirements. The bullet points should avoid
ambiguity to mitigate ambiguity risk in audits. In addition, the last part of the language in this bullet imposing an open
and transparent stakeholder process is unclear. What is the intent behind requiring review in a stakeholder process? If
it is to establish the ability of the entity to develop load shedding procedures beyond those explicitly contemplated in
footnote b, ERCOT questions if it is reasonable for the responsible entity to be required to get “permission” from
stakeholders to implement reliability measures related to its obligation as the functional entity. Again, the language
simply is not clear. Accordingly, ERCOT recommends this bullet point be removed. If it is retained, it should be revised
consistent with these comments to remove ambiguous language to mitigate potential confusion around the
meaning/scope of the footnote in the administration of the CMEP. In addition, ERCOT recommends revising the draft
footnote b to allow for planned Demand interruption as a means of mitigation during interim periods when a
unanticipated (such as unexpected demand growth or unit retirements) or temporary change on the system occurs in a

timeframe that is shorter than the time necessary to plan and implement the system upgrades necessary to avoid the
Demand interruption. Finally, in the last paragraph of footnote b, it isn’t clear why “Transmission Service” was changed
to “transfers.” Firm transmission service is a service provided in some regions, and it provides relative value to other
types of services—e.g., non-firm and network. The mention of transmission service may also be irrelevant in this
footnote, since the allowance of its interruption doesn't also allow for load shedding. Therefore, ERCOT recommends
eliminating the last paragraph of footnote b.
Group
Bonneville Power Administration
Denise Koehn
Yes
Individual
Kasia Mihalchuk
Manitoba Hydro
Yes
The changes to Table 1 Note b proposed by the SDT for this second posting are a reasonable approach to the issue of
interrupting of “Firm Demand”. The requirement to evaluate alternatives to dropping of Firm Demand in a transparent
stakeholder process should provide the verification of cost over benefit on a case by case basis. I propose the following
editorial changes: 1. The change of “Firm Transmission Services” made in Table 1 should be also be made in each
TPL standard as R1 refers to “projected Firm (non-recallable reserved) Transmission Services. 2. Since “Firm Demand”
is a defined term, ensure it is capitalized throughout the standard. There is one instance where it is not.
Individual
Charles Lawrence
American Transmission Company
No
The revised draft is a significant improvement over the first draft. However, we suggest the following minor changes: 1.
The criterion of “adversely affect overall BES reliability” is undefined and may subject to a wide range of interpretation
by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words “as defined by each
Transmission Planner or Planning Authority”. 2. The term of “firm transfers” is undefined and may subject to a wide
range of interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest establishing a
definition for the term of "firm transfers", reverting to the “Firm Transmission Service” term, or using another appropriate
NERC defined term.
Individual
Kathleen Goodman
ISO New England Inc.
No
ISO New England does not allow non-consequential load loss for first contingencies in Planning Analysis, and as an
overall matter, ISO-NE believes that the appropriate step is for NERC to modify the footnote in line with the original
FERC Order. However, ISO-NE offers the following recommendation to improve the proposed language for footnote b
if it is to be retained similar to what has been proposed. In short, ISO-NE proposes changing the third sub-bullet,
because the provision is both unnecessary and inappropriate for a NERC Standard. First, the sub-bullet is redundant,
because the Commission has ordered that companies add to their Open Access Transmission Tariffs an open and
transparent planning process. If Transmission Planners establish their system planning assessments through those
processes, then there should be no question that the Planner’s assessments have been effectively communicated to
the region. Second, the passive nature of the language (i.e., “where the application is subject to review and
acceptance…”) is unclear as it suggests that someone other than the Planning Coordinator/Transmission Planner is
responsible for determining what belongs in a long-term system assessment. Including Demand-Side Management in
the standard also appears redundant as Demand Response is used as an asset in the same manner as generation
resources. b) When interruption of Demand is utilized within the planning process, such interruption is limited to: 1)
Demand that is directly served by the elements that are removed from service as a result of the Contingency. 2)
Interruptible Demand or Demand-Side Management 3) Instances where the planned or controlled interruption of
Demand results in System performance which meets the requirements of Table 1 for Category B contingencies. When
such Demand interruption is utilized in an assessment, the use of such actions must be limited to small portions of the
system, be operationally achievable, be of limited duration, and be documented therein.
Individual
Dan Rochester
Independent Electricity System Operator
Yes

Individual
Ed Davis
Entergy Services
No
Entergy disagrees with the proposed language in the third bullet for two reasons. 1. While Entergy supports the idea of
“an open and transparent stakeholder process” regarding the use of non-consequential load loss. It is unclear how
such a process could be fairly implemented as competing stakeholder interests could prevent resolution. Stakeholders
should be defined as those stakeholders whose load could be shed per footnote b, not any and all stakeholders. 2. The
“is subject to review and acceptance” implies that some formal voting process would be required by stakeholders. Is
this the SDT’s intent? If so would such a process be developed as part of the standard or would it be left up to TO’s? If
non-consequential load loss was deemed an acceptable solution across a SEAM, would the TO’s jointly serving the
load need to agree?
Group
Dominion
Louis Slade, Jr.
Yes
Individual
Terry Harbour
MidAmerican Energy
No
While the TPL note “b” approach has improved, MidAmerican has concerns that including the wording “review and
acceptance” goes beyond the FERC Order 890 order, process, and intent of including the open review process.
Therefore, to align with FERC Order 890, the “review and acceptance” should be replaced with “subject to comment”.
Anything more exceeds FERC Order 890 and the reason why the review process was included. In the end,
Transmission Owning and Operating entities must have final say in the operation of the grid. Entities can comment, but
cannot obstruct Transmission Owning and Operating entities from properly operating the grid or reliability could be
reduced.
Group
Southern Company
Andy Tillery
No
The revised text relating to the planning process exceeds what is appropriate for a reliability standard. Existing open
and transparent stakeholder processes focus on larger system issues and not on local load serving. We suggest that
the drafting team go back to the concept of local load being the load that is made temporarily radial by the contingency.
That was a much better approach.
Individual
Patrick Farrell
Southern California Edison Company
Yes
SCE appreciates the efforts of the NERC Standards Drafting Team and believes that the team has admirably worked to
meet FERC's expectations. SCE would suggest that Footnote "b" be revised to include a semi-colon(;) after the first
sub-paragraph and a semi-colon(;) followed by an "and" after the second sub-paragraph, to convey that the three subparagraphs are alternative, rather than additive methods for satisfying the requirements for "interruptions."
Individual
Jonathan Appelbaum
United Illuminating Co
No
United Illuminating believes that for TPL Category B contingencies no planned or controlled (non-consequential)
interruption of firm demand should occur as a general philosophy for planning the Bulk Electric System (BES).
Recognizing there are certain areas of the BES that have unique circumstances that may warrant an exception to this,
UI suggests the addition of language that recognizes the limited application of non-consequential load interruption with
a process that requires a case-by-case acceptance of such application by the Regional Entity or NERC.
Individual
Michael Moltane
ITC
Yes

The proposed language for the new TPL-001-1 Table 1 footnote b is acceptable to ITC.
Individual
Gregory Campoli
New York Independent System Operator
Yes
The NYISO agrees in principle with the proposed changes, but recommends the following modifications: 1. The
introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly connected
should be interrupted. However, it is an acceptable practice to allow for some Interruption of Demand that is directly
connected to the element that is removed from service. The introductory paragraph is immaterial to the requirement,
and therefore unnecessary with the exception of the last sentence which starts the bulleted list. 2. Interruptible demand
is an operation tool and not a transmission planning tool, while Demand-Side Management is typically embedded in the
load forecast used in the planning process. The second bullet therefore may not be necessary or applicable here,
though it is helpful in making clear those are acceptable forms of interruption. 3. The third bullet is confusing. Suggest
revising the wording to clarify the adverse impact to the BES system and documentation expectations. Recommend
removing reference to the application being subject to review and acceptance in an open and transparent stakeholder
process; this is inherent to all documentation and does not need to be emphasized in a footnote. 4. In the last sentence
of the last paragraph, “would” should be replaced by “must”. 5. The Drafting Team should reconsider the use of “Load”
as opposed to “Demand”. By definition (NERC Glossary dated April 20, 2010) Demand is: 1. The rate at which electric
energy is delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given
instant or averaged over any designated interval of time. 2. The rate at which energy is being used by the customer.”
Load is defined as: “An end-use device or customer that receives power from the electric system.” This terminology is
more appropriate to the application used in the Table. Possible rewording of footnote “b” to be considered: b) Under the
limited circumstances when interruption of Load is utilized within the planning process to address BES performance
requirements, such interruption is limited to: o Load that is directly served by the elements that are removed from
service as a result of the Contingency o Interruptible Load or Demand-Side Management o Demand that does not
adversely impact overall BES reliability where the circumstances for the use of such Load interruption and alternatives
evaluated are documented. Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of
available resources, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s
planning region are relied upon, Facility Ratings in those regions must also be respected.
Individual
David Kiguel
Hydro One Networks Inc.
No
1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of Demand that is
directly connected to the element that is removed from service. Recommend that the drafting team revise the wording
to eliminate this implication, and soften the expectation such that it is recognized that some Interruption of Demand is
unavoidable by system configuration, but that each entity should establish a reasonable limit on how much demand can
be interrupted due to the loss of an element. 2. The Statement that “However, Demand may need to be interrupted in
limited circumstances to address BES performance requirements” in the introductory paragraph contradicts bullet 3
“Demand that does not adversely affect BES …” 3. The third Bullet is confusing. Suggest revising the wording to clarify
the adverse impact to the BES system, documentation expectations, and to answer fundamental questions such as
who has the authority to decide the use if the stakeholder process is “accepting”, and the necessity of having a
stakeholder process. It is unlikely that the interruption of Demand will adversely impact the BES system. This constraint
is too broad. The language in this bullet also allows that non-consequential Demand interruption could be used to
mitigate reliability violations arising from the NERC Category B contingency events (i.e., single element contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified. 5. In the
last sentence of the second paragraph, “would” should be replaced by “must”. Alternatively, possible rewording of
footnote “b” to be considered: b) An objective of the planning process should be to minimize the likelihood of
interrupting Demand and measures to mitigate such interruption should be pursued within the planning process.
However, Demand may need to be interrupted in limited circumstances to address BES performance requirements or
other local reasons which have no adverse impact on overall BES reliability or the interconnected BES. When
interruption of Demand is utilized within the planning process, such interruption is limited to: o Demand that is directly
served by the elements that are removed from service as a result of the Contingency o Demand that does not
adversely impact overall reliability of the BES or the interconnected BES and where the circumstances describing the
use of such Demand interruption are documented, including alternatives evaluated; and where the application is
subject to review and acceptance in an open and transparent stakeholder process. Curtailment of firm transfers is
allowed, when coupled with the appropriate re-dispatch of available resources, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in
those regions would also be respected. The Drafting Team should reconsider the use of “Load” as opposed to
“Demand”. By definition (NERC Glossary dated April 20, 2010) Demand is: “1. The rate at which electric energy is

delivered to or by a system or part of a system, generally expressed in kilowatts or megawatts, at a given instant or
averaged over any designated interval of time. 2. The rate at which energy is being used by the customer.” Load is
defined as: “An end-use device or customer that receives power from the electric system.” This terminology is more
appropriate to the application used in the Table.
Individual
Jason Marshall
Midwest ISO
No
Overall, we believe the changes are reasonable. However, we propose to strike "and where the application is subject to
review and acceptance in an open and transparent stakeholder process.” Stakeholder review processes should not be
mandated through enforceable standards as they do not provide a clear benefit to reliability. Further, FERC Order 890
already mandates an open and transparent process related to the planning of the bulk electric system.
Individual
Claudiu Cadar
GDS Associates Inc.
No
We appreciate all the work conducted by SDT to adjust current footnote “b” however, we disagree with the current
approach as follows below: - The definition does not go far enough with recognition that interruption of Demand should
be mitigated if at all possible. The previous language may have been inadequate, but the current language does not
encourage the TP to develop mitigation plans that could be implemented as an alternative to Demand interruption. Use of Interruptible Demand should only be implemented if the Transmission Planner can point to a contract between
the Transmission Provider and Transmission Customer that permits load curtailment. - Under FERC Order 890,
Conditional Firm transmission service can be granted for entities who voluntarily acknowledge the right of the
Transmission Provider to curtail their transaction or provide re-dispatch. This should be the only transfer which can be
utilized in the Planning Horizon for interruption of Demand for Note b. Suggested language to find the balance point in
the tone of this note is below: “An objective of the planning process is to develop mitigation plans that do not call for the
curtailment of Demand, as interruption of Demand places specific customer groups at a reliability risk that varies from
their counterparts in other areas of the BES. There may be rare instances, however, where interruption of Demand can
be considered a short-term bridge to a mitigation plan which does not rely on negatively impacting certain customer
segments. When interruption of Demand is utilized within the planning process, such interruption is limited to: o
Demand that is directly served by the elements that are removed from service as a result of the Contingency, o
Interruptible Demand or Demand-Side Management, where the Customer has given explicit rights to the Transmission
Provider for curtailment of their Demand, o Demand, other than Interruptible Demand or Demand-Side Management,
that does not adversely impact overall BES reliability where the circumstances describing the use of such Demand are
documented, including alternatives evaluated; where the Load-Serving Entity who has responsibility for serving such
Demand has agreed to the curtailment, and where the application is subject to review and acceptance in an open and
transparent stakeholder process. Curtailment of Firm transfers is allowed, when coupled with the appropriate redispatch of resources obligated to re-dispatch per the terms and conditions of the confirmed transmission service
request between the Transmission Customer and Transmission Provider, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of and firm Demand.
Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions would also be respected. In addition, any Conditional Firm transfers may be curtailed, in accordance with the
terms and conditions of the confirmed transmission service request between the Transmission Customer and
Transmission Provider.”
Individual
Chifong Thomas
Pacific Gas and Electric Co.
Yes
Group
IRS Standards Review Committee
Ben Li
Yes
Individual
Catherine Koch
Puget Sound Energy
Yes
PSE agrees with the foot note b as stated. As it states for any category B outage there wouldn't be any non-

consequential load loss allowed unless a full study is performed with evaluation of alternatives and is approved by
stakeholders. Also, one could curtail firm transfers if re-dispatch of resource is possible. However, there is still some
ambiguity in when approval from stakeholders (time-line)should be sought and who the stakeholders could be
(customers, effected utilities etc.). Hence, PSE would like to revise the footnote by adding the following to the end of
the footnote, ".... at least 2 years prior to the implementation. All the affected parties must review and agree upon the
loss of demand proposal."
Group
IRC Standards Review Committee
Ben Li
Yes
Individual
Harold Wyble
Kansas City Power & Light
No
KCPL appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable proposal for
clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also commend NERC staff for
convening an industry technical conference to discuss the topic and FERC staff for their participation in the technical
conference as the industry carefully considered various perspectives. Although the proposed footnote B is much
improved from the prior draft proposals, KCPL proposes is to strike the text following the semicolon in the third bullet
item which states “and where the application is subject to review and acceptance in an open and transparent
stakeholder process.” This text may be intended as explanatory but has the appearance of mandating an approval
process that will be auditable through the TPL reliability standards. The statement is not needed within the framework
of mandatory reliability requirements as FERC Order 890 already mandates an open and transparent process related
to the planning of the bulk electric system. FERC via the 890 Final Rule modified the pro forma Open-Access
Transmission Tariff to require open and transparent stakeholder process to better ensure no undue discrimination and
access to the transmission system. The Final Rule beginning at paragraph 418 discusses reform to the Coordinated,
Open and Transparent Planning of the transmission system. The Commission direction included eight planning
principles required to be within the open process – one of which is dispute resolution. It should be well understood that
the transmission planner and planning coordinator share and disseminate all of their planning study results and
proposed corrective actions – including the proposed use of Demand interruption – as part of their adherence to Order
890.

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project
20010-11
The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on
the revised footnote. These standards were posted for a 30-day informal public comment
period from September 8, 2010 through October 8, 2010. The stakeholders were asked to
provide feedback on the standards through a special Electronic Comment Form. There were
42 sets of comments, including comments from more than 96 different people from
approximately 75 companies representing 7 of the 10 Industry Segments as shown in the
table on the following pages.
Comments can be reviewed in their original format on the following project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html

Industry response was divided in relation to support for the proposed footnote ‘b’
which was posted for an informal comment period through October 8, 2010.
Although there were a number of supporters for the proposed footnote they were
outnumbered by the commenters who did not support the footnote text for various
reasons and offered their views and concerns.
The Standard Drafting Team (SDT) carefully considered the feedback provided
including minority opinions such as not allowing Demand interruption at all and has
made clarifying revisions to the footnote ‘b’ text.
The revised footnote ‘b’ is:
b) An objective of the planning process is to avoid should be to minimize the
likelihood and magnitude of interruption of Demand following Contingency
events. Interruption of Demand is discouraged and measures to mitigate such
interruption should be pursued within the planning process. However, it is
recognized that Demand may need to will be interrupted if it is directly served
by the elements removed from service as a result of the Contingency.
Furthermore, in limited circumstances Demand may need to be interrupted to
address BES performance requirements. When interruption of Demand is
utilized within the planning process to address BES performance requirements,
such interruption is limited to:
•
•
•

Demand that is directly served by the elements that are removed from
service as a result of the Contingency
Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability where the
cCircumstances describing where the use of such Demand interruption are
documented, including alternatives evaluated; and where the application
Demand interruption is subject to review and acceptance in an open and
transparent stakeholder process that includes addressing stakeholder
comments.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Based on the review of comments received and the fact that only clarifying changes were
made due to those comments, the SDT is recommending that this project be moved forward
to balloting.
If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition, there is
a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Index to Questions, Comments, and Responses
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC
Orders which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding
the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system. Do you agree with the proposed changes and if not,
please provide specific reasons for your disagreement.…. ......................................... 9

October 27, 2010

3

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

Additional Member

Northeast Power Coordinating Council
Additional Organization

New York State Reliability Council, LLC

NPCC 10

2. Gregory Campoli

New York Independent System Operator

NPCC 2

3. Micahel Schiavone

National Grid

NPCC 1

4. Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5. Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC 1

6. Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7. Dean Ellis

Dynegy Generation

NPCC 5

4

5

6

7

8

9

10

NPCC 8

9. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

10. Brian L. Gooder

Ontario Power Generation Incorporated

NPCC 5

11. Kathleen Goodman

ISO - New England

NPCC 2

12. Chantel Haswell

FPL Group, Inc.

NPCC 5

13. David Kiguel

Hydro One Networks Inc.

NPCC 1

14. Michael R. Lombardi

Northeast Utilities

NPCC 1

October 27, 2010

3

Region Segment Selection

1. Alan Adamson

8. Brian Evans-Mongeon Utility Services

2

4

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

15. Randy MacDonald

New Brunswick System Operator

NPCC 2

16. Bruce Metruck

New York Power Authority

NPCC 6

17. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

18. Robert Pellegrini

The United Illuminating Company

NPCC 1

19. Si Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

20. Saurabh Saksena

National Grid

NPCC 1

Philip R. Kleckley

SERC Planning Standards Subcommittee

2.

Group

Additional
Member

Additional
Organization

Region

Bob Jones

Southern Company Services - Trans

SERC

1

John Sullivan

Ameren

SERC

1

3.

Charles Long

Entergy

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative

SERC

1

5.

Pat Huntley

SERC Reliability Corporation

Carol Gerou

Additional Member

6

7

8

9

10

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

WPS Corporation

MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Murdock

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

October 27, 2010

5

10

MRO's NERC Standards Review
Subcommittee

Additional Organization

4

Segment Selection

2.

Group

3

1, 3, 5

1.

3.

2

5

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12. Scott Nickels

Rochester Public Utilties

MRO

4

MRO

1, 3, 5, 6

13. Terry Harbour

4.

Group

MidAmerican Energy Company

Denise Koehn

Additional Member

Bonneville Power Administration

Additional Organization
BPA, Transmission Planning

WECC 1

2. Berhanu Tesema

BPA, Transmission Planning

WECC 1

3. Kyle Kohne

BPA, Transmission Planning

WECC 1

4. Kendall Rydell

BPA, Transmission Planning

WECC 1

5. Rebecca Berdahl

BPA, Long Term Sales and Purchases WECC 3

Group

Louis Slade, Jr.

3

4

5

6

7

8

9

1, 3, 5, 6

Region Segment Selection

1. Chuck Matthews

5.

2

Dominion

1, 3, 5, 6

Additional Member Additional Organization Region Segment Selection
1. Angela Park

Electric Transmission

SERC

1, 3

2. John Loftis

Electric Transmission

SERC

1, 3

3. Mike Garton

Electric Market Policy

NPCC 5, 6

4. Michael Gildea

Electric Market Policy

RFC

6.

Ben Li

Group

5, 6

IRC Standards Review Committee

2

Additional Member Additional Organization Region Segment Selection
1. Bill Phillips

MISO

MRO

2

2. Partick Brown

PJM

RFC

2

3. James Castle

NYISO

NPCC 2

4. Mark Thompson

AESO

WECC 2

5. Charles Yeung

SPP

SPP

6. Greg Van Pelt

CAISO

WECC 2

7. Matt Goldberg

ISO-NE

NPCC 2

October 27, 2010

2

6

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7.

Individual

Jana Van Ness

Arizona Public Service Company

X

X

X

8.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

9.

Individual

John Cummings

PPL Corp

X

X

X

10.

Individual

Andy Tillery

Southern Company

X

X

11.

Individual

Don Gilbert

JEA

X

X

X

12.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

X

X

X

X

13.

Individual

Laura Zotter

ERCOT ISO

14.

Individual

Greg Rowland

Duke Energy

X

X

X

X

15.

Individual

Steve Stafford

Georgia Transmission Corporation

X

16.

Individual

John Canavan

NorthWestern Energy

X

17.

Individual

Tim Ponseti

TVA Transmission Planning & Compliance

X

X

X

18.

Individual

Gordon Rawlings

BC Hydro

X

X

X

19.

Individual

Jon Kapitz

Xcel Energy

X

X

X

X

20.

Individual

John Sullivan

Ameren

X

X

X

X

21.

Individual

Darcy O'Connell

California ISO

22.

Individual

Doug Hohlbaugh

FirstEnergy

X

X

October 27, 2010

7

8

9

X

X

X

X

X
X

X

X

7

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

23.

Individual

Orlando A Ciniglio

Idaho Power

X

X

X

24.

Individual

Michael Lombardi

Northeast Utilities

X

X

X

25.

Individual

Thad Ness

American Electric Power

X

X

X

X

26.

Individual

JC Culberson

ERCOT

27.

Individual

Kasia Mihalchuk

Manitoba Hydro

X

X

X

X

28.

Individual

Charles Lawrence

American Transmission Company

X

29.

Individual

Kathleen Goodman

ISO New England Inc.

X

30.

Individual

Dan Rochester

Independent Electricity System Operator

X

31.

Individual

Ed Davis

Entergy Services

X

X

X

X

32.

Individual

Terry Harbour

MidAmerican Energy

X

X

X

X

33.

Individual

Patrick Farrell

Southern California Edison Company

X

X

X

X

34.

Individual

Jonathan Appelbaum

United Illuminating Co

X

35.

Individual

Michael Moltane

ITC

X

36.

Individual

Gregory Campoli

New York Independent System Operator

37.

Individual

David Kiguel

Hydro One Networks Inc.

38.

Individual

Jason Marshall

Midwest ISO

October 27, 2010

7

8

9

X

X
X

X
X

8

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

39.

Individual

Claudiu Cadar

GDS Associates Inc.

X

40.

Individual

Chifong Thomas

Pacific Gas and Electric Co.

X

41.

Individual

Catherine Koch

Puget Sound Energy

X

42.

Individual

Harold Wyble

Kansas City Power & Light

X

October 27, 2010

2

3

4

5

X

X

X

X

6

7

8

9

X

9

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with FERC Orders which required the
ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system. Do you agree with the proposed changes
and if not, please provide specific reasons for your disagreement.
Summary Consideration: Industry response was divided in relation to support for the proposed footnote ‘b’ which

was posted for an informal comment period through October 8, 2010. Although there were a number of supporters
for the proposed footnote they were outnumbered by the commenters who did not support the footnote text and
offered their views and concerns.
The Standard Drafting Team (SDT) carefully considered the feedback provided and has made clarifying revisions to
the footnote ‘b’ text. For each major item, the SDT has addressed the issue raised and has summarized any
revision made to footnote ‘b’ in response to the feedback provided. The SDT appreciates industry input and believes
the changes made are responsive to the comments received.
Open and Transparent Process: Most of the comments received related to the use of an “open and transparent”
stakeholder process as described in the proposed footnote ‘b’. While the comments on this topic varied, the
majority of comments indicated that such a process should not be included within a mandatory Reliability Standard
and cited that FERC Order 890 already requires the sharing of planning information. Others indicated that the
statement for “review and acceptance” exceeds expectations required by FERC Order 890 and that an entity’s
compliance to a Reliability Standard should not be subject to the “acceptance” of stakeholders and that a process
conforming with FERC Order 890 principles already requires dispute resolution. Some commenters expressed
support of the process and it is noted that those who responded “Yes” with no comment were assumed to support
the process “as is”.
The SDT’s inclusion of a stakeholder review in footnote ‘b’ was driven by the fact that FERC Order 890 does not fully
cover the continent-wide footprint addressed by a NERC Reliability Standard. Additionally, footnote ‘b’ is being
applied to address localized Bulk Electric System performance and not a wide-area Bulk Electric System concern
that is generally the focus of the “open and transparent” process governed by FERC Order 890.
The SDT thoroughly considered all comments on the stakeholder process model. The SDT continues to support a
Reliability Standard providing mandatory enforcement utilizing a stakeholder process where any intended use of
planned Demand interruption has transparency and that stakeholders have the opportunity to comment on its use.
However, upon further reflection the majority of SDT members agreed that including the “acceptance” aspect of the

October 27, 2010

10

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

stakeholder process presents challenges within the context of a Reliability Standard and “acceptance” has been
removed. The SDT agrees with opinions that an entity’s compliance should not be subject to the “acceptance” of its
plans by stakeholders. Also, the SDT realizes that for most entities there is a final, high level review with
acceptance or approval of Transmission plans at the local level. So, while the footnote no longer references the
need for stakeholder acceptance, the expectation is that there will be a review process in place that will consider the
implementation of any plan calling for Demand interruption as explained in the footnote.
In addition, the SDT has revised footnote ‘b’ to explicitly require a response to any challenges presented via the
stakeholder process.
Demand vs. Load: Several commenters questioned the SDT’s use of the term “Demand” instead of “Load” in the
proposed footnote. The SDT clarifies that this was intentional as the existing, approved TPL suite of standards uses
the term Demand throughout the requirement text. Additionally, the existing, approved TPL performance
requirements documented in Table I contain the column heading “Loss of Demand or Curtailed Firm Transfers”
which is the subject of the footnote ‘b’ applicability for category B (single element) Contingencies. This project,
Project 2010-11, aims to address footnote ‘b’ regulatory directives with no change to the remainder of the standard.
Therefore, for consistency with the existing standard text, the term Demand is retained.
Firm transfer vs. Firm Transmission Service: Some stakeholders suggested that the SDT revert back to the
use of “Firm Transmission Service” instead of the undefined term “firm transfers.” The SDT clarifies that that the
change to “firm transfers” was intentional as the existing, approved TPL suite of standards references “firm
transfers” both in requirement text and Table I. The existing, approved TPL performance requirements documented
in Table I contain the column heading “Loss of Demand or Curtailed Firm Transfers” which is the subject of the
footnote ‘b’ applicability for category B (single element) Contingencies. This project, Project 2010-11, aims to
address footnote ‘b’ regulatory directives with no change to the remainder of the standard. Therefore for
consistency with the existing standard text, the term ‘firm transfer’ is retained.
Amount of Demand Loss: The majority of commenters agree with the SDT’s clarifications regarding interruption
of Demand as defined in the proposed footnote ‘b’. The majority of entities who commented support the limited use
of Demand interruption and that when used to address a BES performance requirement agree that it should be
documented, and made known through a stakeholder process. However, as stated above, the majority stopped
short of supporting a mandatory Reliability Standard requiring “acceptance” by other entities for the planned
interruption of Demand.

October 27, 2010

11

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Other minority views propose to limit or cap the amount of Demand loss and some suggested 50 MW as the
appropriate level. Some felt the SDT’s prior approach of limiting the Demand loss to only “radial” line configurations
was appropriate and superior to the “open process” approach. It is also noted that some commenters went further
to say no loss of Demand should be allowed for a single Contingency, but this was clearly a minority view of the
comments submitted.
The SDT carefully considered the comments and unanimously agreed that defining a Demand level limit is
problematic based on the vast differences in BES applications across the continent and that each potential use is
case specific. The SDT also had concerns that setting such a limit may have the unintended consequences of
planned Demand interruption being more widely accepted in practice in Transmission planning. The SDT and most
commenters are of the opinion that a stakeholder review process is a better deterrent for Demand interruption and
will appropriately guard against any misuse.
The revised footnote ‘b’ is:
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of
interruption of Demand following Contingency events. Interruption of Demand is discouraged and measures to
mitigate such interruption should be pursued within the planning process. However, it is recognized that
Demand may need to will be interrupted if it is directly served by the elements removed from service as a result
of the Contingency. Furthermore, in limited circumstances Demand may need to be interrupted to address BES
performance requirements. When interruption of Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to:
•
•
•

Demand that is directly served by the elements that are removed from service as a result of the Contingency
Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability where the cCircumstances describing where the
use of such Demand interruption are documented, including alternatives evaluated; and where the application
Demand interruption is subject to review and acceptance in an open and transparent stakeholder process that
includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.

October 27, 2010

12

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization
Northeast Power Coordinating
Council

Yes or No

Question 1 Comment

No

1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. Recommend that the drafting
team revise the wording to eliminate this implication, and soften the expectation such that it is recognized that
some Interruption of Demand is unavoidable by system configuration, but that each entity should establish a
reasonable limit on how much demand can be interrupted due to the loss of an element.
2. The Statement that “However, Demand may need to be interrupted in limited circumstances to address
BES performance requirements” in the introductory paragraph contradicts bullet 3 “Demand that does not
adversely affect BES ...”
3. The third Bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system,
documentation expectations, and to answer fundamental questions such as who has the authority to decide
the use if the stakeholder process is “accepting”, and the necessity of having a stakeholder process. It is
unlikely that the interruption of Demand will adversely impact the BES system. This constraint is too broad.
The language in this bullet also allows that non-consequential Demand interruption could be used to mitigate
reliability violations arising from the NERC Category B contingency events (i.e., single element
contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified.
5. In the last sentence of the second paragraph, “would” should be replaced by “must”.
Alternatively, possible rewording of footnote “b” to be considered: b) An objective of the planning process
should be to minimize the likelihood of interrupting Demand and measures to mitigate such interruption
should be pursued within the planning process. However, Demand may need to be interrupted in limited
circumstances to address BES performance requirements or other local reasons which have no adverse
impact on overall BES reliability or the interconnected BES. When interruption of Demand is utilized within
the planning process, such interruption is limited to: o Demand that is directly served by the elements that are
removed from service as a result of the Contingency o Demand that does not adversely impact overall
reliability of the BES or the interconnected BES and where the circumstances describing the use of such
Demand interruption are documented, including alternatives evaluated; and where the application is subject to
review and acceptance in an open and transparent stakeholder process. Curtailment of firm transfers is
allowed, when coupled with the appropriate re-dispatch of available resources, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of
any firm Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon,
Facility Ratings in those regions would also be respected.
The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC

October 27, 2010

13

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
Glossary dated April 20, 2010) Demand is:”1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table.

Hydro One Networks Inc.

No

1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. Recommend that the drafting
team revise the wording to eliminate this implication, and soften the expectation such that it is recognized that
some Interruption of Demand is unavoidable by system configuration, but that each entity should establish a
reasonable limit on how much demand can be interrupted due to the loss of an element.
2. The Statement that “However, Demand may need to be interrupted in limited circumstances to address
BES performance requirements” in the introductory paragraph contradicts bullet 3 “Demand that does not
adversely affect BES ...”
3. The third Bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system,
documentation expectations, and to answer fundamental questions such as who has the authority to decide
the use if the stakeholder process is “accepting”, and the necessity of having a stakeholder process. It is
unlikely that the interruption of Demand will adversely impact the BES system. This constraint is too broad.
The language in this bullet also allows that non-consequential Demand interruption could be used to mitigate
reliability violations arising from the NERC Category B contingency events (i.e., single element
contingencies).
4. In the second paragraph, the conditions when interruption of Firm Transfers may be used are not specified.
5. In the last sentence of the second paragraph, “would” should be replaced by “must”. Alternatively, possible
rewording of footnote “b” to be considered: b) An objective of the planning process should be to minimize the
likelihood of interrupting Demand and measures to mitigate such interruption should be pursued within the
planning process. However, Demand may need to be interrupted in limited circumstances to address BES
performance requirements or other local reasons which have no adverse impact on overall BES reliability or
the interconnected BES. When interruption of Demand is utilized within the planning process, such
interruption is limited to: o Demand that is directly served by the elements that are removed from service as a
result of the Contingency o Demand that does not adversely impact overall reliability of the BES or the
interconnected BES and where the circumstances describing the use of such Demand interruption are
documented, including alternatives evaluated; and where the application is subject to review and acceptance
in an open and transparent stakeholder process. Curtailment of firm transfers is allowed, when coupled with
the appropriate re-dispatch of available resources, where it can be demonstrated that Facilities remain within

October 27, 2010

14

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those
regions would also be respected.
The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC
Glossary dated April 20, 2010) Demand is:”1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table.

SERC Planning Standards
Subcommittee

No

The revised text relating to the planning process exceeds what is appropriate for a reliability standard.
Existing open and transparent stakeholder processes focus on larger system issues and not on local load
serving. We suggest the following: Demand may need to be interrupted in limited circumstances to address
BES performance requirements. When interruption of Demand is utilized within the planning process, such
interruption is limited to: o Demand that is directly served by the elements that are removed from service as a
result of the Contingency o Interruptible Demand or Demand-Side Management o Demand that does not
adversely impact overall BES reliability and is made temporarily radial as a result of the Contingency, where
that Demand must be interrupted to meet performance requirements. Curtailment of firm transfers is allowed
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in
the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region are
relied upon, Facility Ratings in those regions would also be respected. “
The comments expressed herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC
Reliability Corporation, its board, or its officers.”

Ameren

No

October 27, 2010

The revised text to footnote b relating to the planning process exceeds what is appropriate for a reliability
standard. Existing open and transparent stakeholder processes focus on larger system issues rather than on
local load serving issues. We suggest the following text for footnote b:Demand may need to be interrupted in
limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to: o Demand that is directly served by the elements
that are removed from service as a result of the Contingency o Interruptible Demand or Demand-Side
Management o Demand that does not adversely impact overall BES reliability and is made temporarily radial
as a result of the Contingency, where that Demand must be interrupted to meet performance requirements.
Curtailment of firm transfers is allowed when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the

15

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.

MRO's NERC Standards Review
Subcommittee

No

The revised draft is a significant improvement over the first draft. However, we suggest the following minor
changes:
1. The criterion of “adversely affect overall BES reliability” is undefined and maybe subject to a wide range of
interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words
“as defined by each Transmission Planner or Planning Authority”.
2. The term of “firm transfers” is undefined and maybe subject to a wide range of interpretation by
Transmission Planners, Planning Authorities, and auditors. So, we suggest establishing a definition for the
term, reverting to the “Firm Transmission Service” term, or using another appropriate defined term.

American Transmission
Company

No

The revised draft is a significant improvement over the first draft. However, we suggest the following minor
changes:
1. The criterion of “adversely affect overall BES reliability” is undefined and may subject to a wide range of
interpretation by Transmission Planners, Planning Authorities, and auditors. So, we suggest adding the words
“as defined by each Transmission Planner or Planning Authority”.
2. The term of “firm transfers” is undefined and may subject to a wide range of interpretation by Transmission
Planners, Planning Authorities, and auditors. So, we suggest establishing a definition for the term of "firm
transfers", reverting to the “Firm Transmission Service” term, or using another appropriate NERC defined
term.

PacifiCorp

October 27, 2010

No

PacifiCorp believes that the current version of footnote “b” is an improvement over the language that currently
exists in the standard, except for one component of the revised footnote. The third bullet in the draft standard
currently limits the interruption of Demand if it does not adversely impact overall BES reliability, where the
circumstances describing the use of the interruption are documented (including alternatives evaluated) and
the application is subject to review and acceptance in “an open and transparent stakeholder process.”
PacifiCorp believes that the language requiring review and acceptance of an application of demand
interruption through any sort of stakeholder process should be removed. It is not practical or effective to
prescribe that either this standard or any other standard requires stakeholder approval in order to maintain
compliance. As presently drafted, this requirement for stakeholder review and acceptance appears to be
inconclusive and indeterminate as to what is required for registered entities to comply. Instead, this third
bullet should require the documentation, by the Planning Authority and Transmission Planner, of the
circumstances describing the use of Demand interruption - including methodologies used, assumptions relied
upon, and alternatives evaluated - as part of the Planning Authorities’ and/or Transmission Planners’

16

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
documentation of results in their annual Reliability Assessments. These annual assessments are already
submitted to the appropriate Regional Reliability Organization pursuant to TPL-002-1b Requirement R3. This
annual assessment can be provided by the ERO to other appropriate third parties upon their request.

Southern Company

No

The revised text relating to the planning process exceeds what is appropriate for a reliability standard.
Existing open and transparent stakeholder processes focus on larger system issues and not on local load
serving. We suggest that the drafting team go back to the concept of local load being the load that is made
temporarily radial by the contingency. That was a much better approach.

JEA

No

The requirement in general is acceptable; however, there needs to be an added "such as" clause to the
referenced "...in an open and transparent stakeholder processes." I suggest adding "..."...in an open and
transparent stakeholder processes such as the FERC approved regional 890 process that includes the load
serving entity affected".

South Carolina Electric and Gas

No

SCE&G believes the first sentence "An object of the planning process is to avoid interruption of Demand."
goes beyond what is appropriate for a reliability standard and therefore should be deleted. Also, the part of
the sentence that states "and where the application is subject to review and acceptance in an open and
transparent stakeholder process" goes beyond what is appropriate for a reliability standard and should be
deleted.

NorthWestern Energy

No

In addition to the three bullet items, add a fourth bullet item to the list of limitations under the body of footnote
b: “In no case will a total loss of load that is less than 50 MW be considered a violation of this standard.”

TVA Transmission Planning &
Compliance

No

TVA supports FERC's actions on improving reliability of the BES; however, TVA believes that the new
proposal is focusing more on reliability of local loads than on the overall reliability of the BES. Footnote b
should focus only on the overall reliability of the BES. Reliability of local loads should be addressed outside
the TPL standards and therefore should not be used/referenced in footnote b. Also existing stakeholder
processes (referred to in the SDT proposal) typically focus on larger system issues and not on local load
serving. Thus TVA believes that some local load should be allowed to be dropped in order to maintain BES
reliability. However TVA does believe that there should be a limit of how much load can be dropped in order
to maintain BES reliability. TVA believes that 50 MW is a reasonable number for this limit. Based on the
above, TVA proposes substituting the following for the revised footnote b:Demand may need to be interrupted
in limited circumstances to address BES performance requirements. When interruption of Demand is utilized
within the planning process, such interruption is limited to: Demand that is directly served by the elements that
are removed from service as a result of the Contingency Interruptible Demand or Demand-Side Management
Demand that does not adversely impact overall BES reliability, where that Demand (not to exceed 50 MW)

October 27, 2010

17

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
must be interrupted to meet performance requirements. Curtailment of firm transfers is allowed when coupled
with the appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any
firm Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions would also be respected.

BC Hydro

No

The SDT is to be commended for their efforts to develop clear, unambiguous language for Footnote “b”.
From the discussions that have taken place it seems that there are many different perspectives and to get
agreement on specific language will be very difficult. We believe that it would be useful to identify the main
issues that Footnote “b” needs to address and we consider those main issues to be:
o Definitions of (a) Consequential Load Loss, (b) Firm Demand, (c) Firm Transmission Capability (as distinct
from the OATT term, “Firm Transmission Service”), (d) Firm Transfer (this could be defined as transfers using
the OATT’s Firm Transmission Service, (e) Manual System Adjustments (capitalized in the Category C
section of TPL-001, but not defined in the NERC Glossary) and (f) the Bulk Electric System (BES).
o Identifying permissible Demand/Transfer curtailment actions for (a) the planning studies simulating the
Category B event itself and (b) the planning studies associated with determining acceptable actions for
preparing for the next set of contingencies should the initial single contingency be prolonged (ie, last several
weeks). This would define the acceptable (pre-emptive) “Manual System Adjustments” of Category C events.
o Define separate acceptable curtailment actions for (a) curtailment of Demand (ie, end-user load) and (b)
curtailment of market to market transfers, that very rarely, if ever, result in the loss of any end-user load.
o Define the planning studies required to determine the acceptability of the impacts on the BES resulting from
curtailments in a “remote” part of the system that have been accepted by those directly affected by those
curtailments.
At this point we don’t have specific language to suggest, but we do have the following comments that we
hope will help:
A. Interruption of Demand:
A.1. Consider improving the definition of “Firm Demand” in the NERC Glossary that now reads, “That portion
of the Demand that a power supplier is obligated to provide except when system reliability is threatened or
during emergency conditions”. Perhaps it could be changed to something like, “That portion of the Demand
that the planned transmission system must be able to supply without interruption for Category B events.
A.2. Consider stating in Footnote “b” that curtailment of Firm Demand is (a) not permitted in the simulation of
the N-1 event itself and (b) it is not permitted as part of the (pre-emptive) “Manual System Adjustments”
needed to prepare for the next set of contingencies should the initial single contingency be prolonged (ie, last

October 27, 2010

18

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
several weeks).
B. Interruption of Firm Transfers:
B.1. “Firm Transfers” could be defined as transfers using the OATT’s Firm Transmission Service, but consider
developing a system reliability-based term for “Firm Transmission Capability” instead of referring to the tariffbased NERC definition of “Firm Transmission Service”. This would recognize the difference between
planning standards and commercial/tariff rules. The NERC definition of “Firm Transmission Service” is now,
“The highest quality (priority) service offered to customers under a filed rate schedule that anticipates no
planned interruption”. Transmission tariffs address the priority of curtailments when the loading on a
transmission path needs to be reduced for whatever reason (single- or multiple-contingencies). The NERC
transmission planning standards need a system reliability definition like, “Firm Transmission Capability” is the
transmission capability across a cut-plane, on a defined transmission path or across a defined flowgate that is
available, before any manual corrective actions are taken, following the worst Category B event under the
most onerous normal system conditions considering all plausible generation dispatch patterns and the full
range of expected load levels.”
B.2. Consider stating in Footnote “b” that curtailment of Firm Transfers is only permitted to the extent that
redispatch of generation can be implemented so that delivery to the Firm Transfer recipient is not interrupted
(a) in the planning studies of the Category B event itself and (b) as part of the (pre-emptive) “Manual System
Adjustments” needed to prepare for the next set of contingencies should the initial single contingency be
prolonged (ie, last several weeks).
C. General Comments:
C.1. Consider replacing the first bullet of the proposed Footnote “b” with simply “Consequential Load Loss”
since the NERC Project 2006 02 (TPL 001) Standard Drafting Team is introducing the following definition:
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result of
Transmission Facilities being removed from service by a Protection System operation designed to isolate the
fault
C.2. Consider removing “Demand-Side Management” (DSM) from the second bullet because that term is too
general. The present definition of DSM in the NERC Glossary is:”The term for all activities or programs
undertaken by Load-Serving Entity or its customers to influence the amount or timing of electricity they use”.
C.3. Consider being more specific on what constitutes acceptable “Interruptible Demand”, like: “Interruptible
Demand that is part of an automatic real-time Direct Control Load Management (DCLM) system that is
activated by the contingencies that require it and that is a completely “dual-redundant” scheme including all
communications equipment. The DCLM system must result in automatic curtailment of Demand that is fast
enough to maintain all BES system performance standards (eg, voltage stability, voltage dip, etc)”.

October 27, 2010

19

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
C.4. Consider eliminating the description of how interrupting Demand that does not adversely impact overall
BES reliability was accepted (ie, the stakeholder process, etc). If such a process were undertaken and it
resulted in acceptance that the Demand could be curtailed for Category B events, wouldn’t that simply mean
that the Demand was “Interruptible Demand”. It really doesn’t matter what process resulted in it being
accepted. The key considerations are that (a) if the interruption of that Demand is necessary to maintain BES
reliability, then it must be interrupted in a very reliable manner (ie, dual redundant scheme, etc) and (b) if the
interruption of that Demand is not necessary to maintain the reliable performance of the BES, then that should
be confirmed by the planning studies (ie, it doesn’t need to have an expensive, sophisticated, dual-redundant
DCLM scheme since the impact on the BES is acceptable even if the scheme doesn’t work).
D. Additional Questions related to Curtailment of Firm Transfers: In the past, the latter part of Footnote B
read: “To prepare for the next contingency, system adjustments are permitted, including curtailments of
contracted Firm (non-recallable reserved) electric power Transfers.”The last part of the proposed Footnote B
now reads: “Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of
resources obligated to re-dispatch, where it can be demonstrated that Facilities remain within applicable
Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities
external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions
would also be respected.”We would like to understand the implications of the proposed Footnote B as it
relates to curtailment of Firm Transfers (as per definition proposed earlier) for the following questions:
1) In the most recent draft of Footnote B, why was the NERC defined term ‘Firm Transmission Service’
replaced with the non-defined term ‘firm transfers’?
2) In the most recent draft of Footnote B, why was the tone softened from “No curtailment of Firm
Transmission Service is allowed, except...” to “Curtailment of firm transfers is allowed when...”?
3) Assuming an outage of a single transmission line (N-1 Category B event) has occurred and assuming that
no “resources [are] obligated to redispatch” for this outage, would a transmission provider be allowed to curtail
Firm Transmission Service (NERC defined term) that it has sold in order to prepare to withstand the next
worst credible contingency?
4) Would transmission providers be allowed to sell Firm Transmission Service on a path above what could be
delivered with any one element of that path out of service and a range of operating conditions?
5) If the proposed Footnote B is approved, would utilities have to reinforce their system (within 60 months) to
ensure that Firm Transmission Service for particular paths would not be curtailed can be delivered when any
one element of that path is out of service?
6) If a transmission provider employs Generation Dropping for single contingencies in order to support Firm
Transmission Service between regions, and assuming there are no provisions for obligated re-dispatch, would

October 27, 2010

20

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
the proposed Footnote B force a recalculation of firm vs non-firm transfer capability?
7) Path 66 (PACI) and Path 65 (PDCI) can both see significant derates in their firm transfer capability for
single contingencies. How would the proposed Footnote B impact Firm Transmission on these paths?

FirstEnergy

No

FirstEnergy appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable
proposal for clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also
commend NERC staff for convening an industry technical conference to discuss the topic and FERC staff for
their participation in the technical conference as the industry carefully considered various perspectives. The
proposed footnote B is much improved from the prior draft proposals.
One change that FirstEnergy proposes is to strike the text following the semicolon in the third bullet item
which states “and where the application is subject to review and acceptance in an open and transparent
stakeholder process.” This text may be intended as explanatory but has the appearance of mandating an
approval process that will be auditable through the TPL reliability standards. The statement is not needed
within the framework of mandatory reliability requirements as FERC Order 890 already mandates an open
and transparent process related to the planning of the bulk electric system. FERC via the 890 Final Rule
modified the pro forma Open-Access Transmission Tariff to require open and transparent stakeholder process
to better ensure no undue discrimination and access to the transmission system. The Final Rule beginning at
paragraph 418 discusses reform to the Coordinated, Open and Transparent Planning of the transmission
system. The Commission direction included eight planning principles required to be within the open process one of which is dispute resolution. It should be well understood that the transmission planner and planning
coordinator share and disseminate all of their planning study results and proposed corrective actions including the proposed use of Demand interruption - as part of their adherence to Order 890. We appreciate
the SDT’s careful consideration of our comments.

Northeast Utilities

No

NU agrees with the language of the proposed revision to Footnote b EXCEPT FOR bullet #3 which suggests
that non-consequential demand interruption could be used to mitigate reliability violations arising from the
NERC Category B contingency events (i.e., single element contingencies).

ERCOT

No

The introductory paragraph of footnote b includes policy language. Since this is a reliability standard-and not
a policy directive-the general narrative setting forth the desired policy goal of minimizing load-shedding is
misplaced. Including policy language can cloud the specific issues the standard attempts to address, and
ERCOT recommends deleting the first two sentences in the introductory paragraph.
The next sentence in the introductory paragraph goes on to state, generally, that demand may be interrupted
to "address BES performance requirements.” This phrase is vague. To which performance requirements
does this refer? The intent is not clear. If the intent is to generally recognize the need to shed load to respect

October 27, 2010

21

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
NERC standards and to allow flexibility for an entity to exercise discretion relative to meeting BES
performance requirements, then that intent should be clearly reflected in the language.
Furthermore, the last sentence of the introductory paragraph and the subsequent bullet points are arguably
inconsistent with this approach, because they could be viewed as removing an entity’s flexibility/discretion by
limiting the circumstances when load can be shed.
The second bullet point is unnecessary, because it is already apparent that interruptible demand/demand side
management programs can be used according to their terms. This could create confusion in that it could be
implied that, absent the need to use these to meet BES performance requirements, using them otherwise is
inconsistent with/not allowed under footnote b. Simply put, those products are not load shedding as
contemplated by this footnote. Therefore they should not be listed here.
With respect to the third bullet point, the phrase "demand that does not adversely impact overall BES
reliability" is not adequately defined, and provides opportunity for confusion. This is an ambiguous phrase
and can’t be linked back to objective NERC standards/requirements. The bullet points should avoid ambiguity
to mitigate ambiguity risk in audits.
In addition, the last part of the language in this bullet imposing an open and transparent stakeholder process
is unclear. What is the intent behind requiring review in a stakeholder process? If it is to establish the ability
of the entity to develop load shedding procedures beyond those explicitly contemplated in footnote b, ERCOT
questions if it is reasonable for the responsible entity to be required to get “permission” from stakeholders to
implement reliability measures related to its obligation as the functional entity. Again, the language simply is
not clear. Accordingly, ERCOT recommends this bullet point be removed. If it is retained, it should be revised
consistent with these comments to remove ambiguous language to mitigate potential confusion around the
meaning/scope of the footnote in the administration of the CMEP.
In addition, ERCOT recommends revising the draft footnote b to allow for planned Demand interruption as a
means of mitigation during interim periods when a unanticipated (such as unexpected demand growth or unit
retirements) or temporary change on the system occurs in a timeframe that is shorter than the time necessary
to plan and implement the system upgrades necessary to avoid the Demand interruption.
Finally, in the last paragraph of footnote b, it isn’t clear why “Transmission Service” was changed to
“transfers.” Firm transmission service is a service provided in some regions, and it provides relative value to
other types of services-e.g., non-firm and network. The mention of transmission service may also be
irrelevant in this footnote, since the allowance of its interruption doesn't also allow for load shedding.
Therefore, ERCOT recommends eliminating the last paragraph of footnote b.

ISO New England Inc.

October 27, 2010

No

ISO New England does not allow non-consequential load loss for first contingencies in Planning Analysis, and
as an overall matter, ISO-NE believes that the appropriate step is for NERC to modify the footnote in line with

22

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
the original FERC Order.
However, ISO-NE offers the following recommendation to improve the proposed language for footnote b if it is
to be retained similar to what has been proposed. In short, ISO-NE proposes changing the third sub-bullet,
because the provision is both unnecessary and inappropriate for a NERC Standard.
First, the sub-bullet is redundant, because the Commission has ordered that companies add to their Open
Access Transmission Tariffs an open and transparent planning process. If Transmission Planners establish
their system planning assessments through those processes, then there should be no question that the
Planner’s assessments have been effectively communicated to the region.
Second, the passive nature of the language (i.e., “where the application is subject to review and
acceptance...”) is unclear as it suggests that someone other than the Planning Coordinator/Transmission
Planner is responsible for determining what belongs in a long-term system assessment.
Including Demand-Side Management in the standard also appears redundant as Demand Response is used
as an asset in the same manner as generation resources.
b) When interruption of Demand is utilized within the planning process, such interruption is limited to:
1) Demand that is directly served by the elements that are removed from service as a result of the
Contingency.
2) Interruptible Demand or Demand-Side Management
3) Instances where the planned or controlled interruption of Demand results in System performance which
meets the requirements of Table 1 for Category B contingencies. When such Demand interruption is utilized
in an assessment, the use of such actions must be limited to small portions of the system, be operationally
achievable, be of limited duration, and be documented therein.

Entergy Services

No

Entergy disagrees with the proposed language in the third bullet for two reasons.
1. While Entergy supports the idea of “an open and transparent stakeholder process” regarding the use of
non-consequential load loss. It is unclear how such a process could be fairly implemented as competing
stakeholder interests could prevent resolution. Stakeholders should be defined as those stakeholders whose
load could be shed per footnote b, not any and all stakeholders.
2. The “is subject to review and acceptance” implies that some formal voting process would be required by
stakeholders. Is this the SDT’s intent? If so would such a process be developed as part of the standard or
would it be left up to TO’s? If non-consequential load loss was deemed an acceptable solution across a
SEAM, would the TO’s jointly serving the load need to agree?

October 27, 2010

23

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment

MidAmerican Energy

No

While the TPL note “b” approach has improved, MidAmerican has concerns that including the wording “review
and acceptance” goes beyond the FERC Order 890 order, process, and intent of including the open review
process. Therefore, to align with FERC Order 890, the “review and acceptance” should be replaced with
“subject to comment”. Anything more exceeds FERC Order 890 and the reason why the review process was
included. In the end, Transmission Owning and Operating entities must have final say in the operation of the
grid. Entities can comment, but cannot obstruct Transmission Owning and Operating entities from properly
operating the grid or reliability could be reduced.

United Illuminating Co

No

United Illuminating believes that for TPL Category B contingencies no planned or controlled (nonconsequential) interruption of firm demand should occur as a general philosophy for planning the Bulk Electric
System (BES). Recognizing there are certain areas of the BES that have unique circumstances that may
warrant an exception to this, UI suggests the addition of language that recognizes the limited application of
non-consequential load interruption with a process that requires a case-by-case acceptance of such
application by the Regional Entity or NERC.

New York Independent System
Operator

Yes

The NYISO agrees in principle with the proposed changes, but recommends the following modifications:
1. The introductory paragraph discourages the Interruption of any Demand, implying that no Demand directly
connected should be interrupted. However, it is an acceptable practice to allow for some Interruption of
Demand that is directly connected to the element that is removed from service. The introductory paragraph is
immaterial to the requirement, and therefore unnecessary with the exception of the last sentence which starts
the bulleted list.
2. Interruptible demand is an operation tool and not a transmission planning tool, while Demand-Side
Management is typically embedded in the load forecast used in the planning process. The second bullet
therefore may not be necessary or applicable here, though it is helpful in making clear those are acceptable
forms of interruption.
3. The third bullet is confusing. Suggest revising the wording to clarify the adverse impact to the BES system
and documentation expectations. Recommend removing reference to the application being subject to review
and acceptance in an open and transparent stakeholder process; this is inherent to all documentation and
does not need to be emphasized in a footnote.
4. In the last sentence of the last paragraph, “would” should be replaced by “must”.
5. The Drafting Team should reconsider the use of “Load” as opposed to “Demand”. By definition (NERC
Glossary dated April 20, 2010) Demand is: 1. The rate at which electric energy is delivered to or by a system
or part of a system, generally expressed in kilowatts or megawatts, at a given instant or averaged over any
designated interval of time. 2. The rate at which energy is being used by the customer.”Load is defined as:”An

October 27, 2010

24

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
end-use device or customer that receives power from the electric system.”This terminology is more
appropriate to the application used in the Table. Possible rewording of footnote “b” to be considered: b) Under
the limited circumstances when interruption of Load is utilized within the planning process to address BES
performance requirements, such interruption is limited to: o Load that is directly served by the elements that
are removed from service as a result of the Contingency o Interruptible Load or Demand-Side Management o
Demand that does not adversely impact overall BES reliability where the circumstances for the use of such
Load interruption and alternatives evaluated are documented. Curtailment of firm transfers is allowed, when
coupled with the appropriate re-dispatch of available resources, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility
Ratings in those regions must also be respected.

Midwest ISO

No

Overall, we believe the changes are reasonable. However, we propose to strike "and where the application is
subject to review and acceptance in an open and transparent stakeholder process.” Stakeholder review
processes should not be mandated through enforceable standards as they do not provide a clear benefit to
reliability. Further, FERC Order 890 already mandates an open and transparent process related to the
planning of the bulk electric system.

GDS Associates Inc.

No

We appreciate all the work conducted by SDT to adjust current footnote “b” however, we disagree with the
current approach as follows below:The definition does not go far enough with recognition that interruption of Demand should be mitigated if at all
possible. The previous language may have been inadequate, but the current language does not encourage
the TP to develop mitigation plans that could be implemented as an alternative to Demand interruption.
- Use of Interruptible Demand should only be implemented if the Transmission Planner can point to a contract
between the Transmission Provider and Transmission Customer that permits load curtailment
.- Under FERC Order 890, Conditional Firm transmission service can be granted for entities who voluntarily
acknowledge the right of the Transmission Provider to curtail their transaction or provide re-dispatch. This
should be the only transfer which can be utilized in the Planning Horizon for interruption of Demand for Note
b. Suggested language to find the balance point in the tone of this note is below:”An objective of the planning
process is to develop mitigation plans that do not call for the curtailment of Demand, as interruption of
Demand places specific customer groups at a reliability risk that varies from their counterparts in other areas
of the BES. There may be rare instances, however, where interruption of Demand can be considered a shortterm bridge to a mitigation plan which does not rely on negatively impacting certain customer segments.
When interruption of Demand is utilized within the planning process, such interruption is limited to: o Demand
that is directly served by the elements that are removed from service as a result of the Contingency, o

October 27, 2010

25

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
Interruptible Demand or Demand-Side Management, where the Customer has given explicit rights to the
Transmission Provider for curtailment of their Demand, o Demand, other than Interruptible Demand or
Demand-Side Management, that does not adversely impact overall BES reliability where the circumstances
describing the use of such Demand are documented, including alternatives evaluated; where the LoadServing Entity who has responsibility for serving such Demand has agreed to the curtailment, and where the
application is subject to review and acceptance in an open and transparent stakeholder process. Curtailment
of Firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch per the terms and conditions of the confirmed transmission service request between the
Transmission Customer and Transmission Provider, where it can be demonstrated that Facilities remain
within applicable Facility Ratings and the re-dispatch does not result in the shedding of and firm Demand.
Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in
those regions would also be respected. In addition, any Conditional Firm transfers may be curtailed, in
accordance with the terms and conditions of the confirmed transmission service request between the
Transmission Customer and Transmission Provider.”

Kansas City Power & Light

No

KCPL appreciates the efforts of the Assess Transmission Future Needs SDT in reaching a reasonable
proposal for clarifying Table 1 footnote B presented in the TPL-001 through TPL-004 standards. We also
commend NERC staff for convening an industry technical conference to discuss the topic and FERC staff for
their participation in the technical conference as the industry carefully considered various perspectives.
Although the proposed footnote B is much improved from the prior draft proposals, KCPL proposes is to strike
the text following the semicolon in the third bullet item which states “and where the application is subject to
review and acceptance in an open and transparent stakeholder process.” This text may be intended as
explanatory but has the appearance of mandating an approval process that will be auditable through the TPL
reliability standards. The statement is not needed within the framework of mandatory reliability requirements
as FERC Order 890 already mandates an open and transparent process related to the planning of the bulk
electric system. FERC via the 890 Final Rule modified the pro forma Open-Access Transmission Tariff to
require open and transparent stakeholder process to better ensure no undue discrimination and access to the
transmission system. The Final Rule beginning at paragraph 418 discusses reform to the Coordinated, Open
and Transparent Planning of the transmission system. The Commission direction included eight planning
principles required to be within the open process - one of which is dispute resolution. It should be well
understood that the transmission planner and planning coordinator share and disseminate all of their planning
study results and proposed corrective actions - including the proposed use of Demand interruption - as part of
their adherence to Order 890.

Puget Sound Energy

Yes

PSE agrees with the foot note b as stated. As it states for any category B outage there wouldn't be any nonconsequential load loss allowed unless a full study is performed with evaluation of alternatives and is
approved by stakeholders. Also, one could curtail firm transfers if re-dispatch of resource is possible.

October 27, 2010

26

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
However, there is still some ambiguity in when approval from stakeholders (time-line) should be sought and
who the stakeholders could be (customers, effected utilities etc.). Hence, PSE would like to revise the
footnote by adding the following to the end of the footnote, ".... at least 2 years prior to the implementation. All
the affected parties must review and agree upon the loss of demand proposal."

Southern California Edison
Company

Yes

SCE appreciates the efforts of the NERC Standards Drafting Team and believes that the team has admirably
worked to meet FERC's expectations.SCE would suggest that Footnote "b" be revised to include a semicolon(;) after the first sub-paragraph and a semi-colon(;) followed by an "and" after the second subparagraph, to convey that the three sub-paragraphs are alternative, rather than additive methods for satisfying
the requirements for "interruptions."

Idaho Power

Yes

footnote 'b' is silent with respect to planned removal from service of certain generators. I believe there are
many conditions out there where a single contingency can initiate a planned (RAS-initiated) removal of
generation. The fact that this is mentioned in footnote 'c', under multiple contingencies, begs the need for
futher elaboration/discussion of this option under single contingencies in footnote 'b'.

Manitoba Hydro

Yes

The changes to Table 1 Note b proposed by the SDT for this second posting are a reasonable approach to
the issue of interrupting of “Firm Demand”. The requirement to evaluate alternatives to dropping of Firm
Demand in a transparent stakeholder process should provide the verification of cost over benefit on a case by
case basis. I propose the following editorial changes: 1. The change of “Firm Transmission Services” made in
Table 1 should be also be made in each TPL standard as R1 refers to “projected Firm (non-recallable
reserved) Transmission Services.2. Since “Firm Demand” is a defined term, ensure it is capitalized throughout
the standard. There is one instance where it is not.

California ISO

Yes

1) Regarding the 2nd bullet provision, we suggest: Interruptible Demand or Demand-Side Management that
has been reviewed and approved by the Planning Authority.
2) Regarding the 3rd bullet provision, we suggest: Demand interruption that does not adversely impact
overall BES reliability....
3) Also regarding the 3rd bullet provision, we suggest replacing acceptance with clarification to read “where
the application is subject to review and clarification in an open and transparent stakeholder process."

Xcel Energy

October 27, 2010

Yes

Xcel Energy supports the new interpretation that would allow curtailment of firm transfers or demand for
limited conditions where the integrity of bulk electric system is not compromised. However Xcel Energy seeks
some clarification regarding the following: The 3rd bullet point in footnote b will need to clarify whether the
demand interruption can be done after the contingency, or before the contingency. If it is allowed after the

27

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Question 1 Comment
contingency, then the standard would allow violation of voltage or thermal loading criteria for a brief period,
after contingency and, before demand curtailment happens. Is this acceptable based on the new
interpretation?
Since TPL-002 standard deals with NERC Category B contingencies, and footnote b states that curtailment of
firm transfers is allowed, it should be clarified if this curtailment is allowed before or after the contingency. If
the curtailment is allowed only after the contingency, then the system would be in violation of the thermal or
voltage criteria for a brief period till the generation is re-dispatched. Is this allowed by the new interpretation?
If curtailment is only allowed in preparation of the contingency, then the firm transfers would be curtailed
during system intact conditions, in preparation for the first contingency, resulting in violation of TPL-001
standard. Is this allowed by the new interpretation?

PPL Corp

Yes

PPL believes that Footnote b as described in TPL-002-1b, Draft 2, August 30, 2010 is fine provided an
accompanying Requirement (with appropriate VRF and VSL) and Measure is added to the TPL standard(s) to
require and document notification of the affected Demand parties and the involvement of the affected
Demand parties in an open process as described by Footnote b, third bullet.

Duke Energy

Yes

Duke Energy strongly supports this revised footnote ‘b’. We believe that it provides for appropriate
consideration of stakeholder input in decision-making for local reliability issues, while maintaining the
reliability of the Bulk Electric System.

ITC

Yes

The proposed language for the new TPL-001-1 Table 1 footnote b is acceptable to ITC.

Bonneville Power Administration

Yes

Dominion

Yes

IRS Standards Review
Committee

Yes

IRC Standards Review
Committee

Yes

Arizona Public Service Company

Yes

ERCOT ISO

Yes

October 27, 2010

28

Consideration of Comments on TPL Table 1 Order (footnote ‘b’) — Project 2010-11

Organization

Yes or No

Georgia Transmission
Corporation

Yes

American Electric Power

Yes

Independent Electricity System
Operator

Yes

Pacific Gas and Electric Co.

Yes

October 27, 2010

Question 1 Comment

29

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards

Standards

Functions That Must Comply
With the Associated
Requirements
Transmission
Planning
Planner
Authority

TPL-001-0.2: System Performance Under Normal (No
Contingency) Conditions (Category A)

X

X

TPL-002-0c: System Performance Following Loss of a Single
Bulk Electric System Element (Category B)
TPL-003-0b: System Performance Following Loss of Two or
More Bulk Electric System Elements (Category C)
TPL-004-0a: System Performance Following Extreme Events
Resulting in the Loss of Two or More Bulk Electric System
Elements (Category D)

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The effective date for footnote ‘b’ will be the first day of the first calendar quarter, 60 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, the effective date will be the first day of the first calendar quarter, 60 months after
Board of Trustees adoption.
All other requirements remain in effect as per previous approvals.

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Informal comment period completed October 8, 2010.
Proposed Action Plan and Description of Current Draft:
This is the third draft of the proposed modification to footnote ‘b’ posted for a 45-day formal
comment period, with an initial ballot to be conducted during the last 10 days of the comment
period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial ballot

December 2010

2. Recirculation ballot

January 2011

3. Submit to BOT for approval

January 2011

4. File with FERC

February 2011

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

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Page 4 of 7

S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of
Demand following Contingency events. However, it is recognized that Demand will be interrupted if it is
directly served by the Elements removed from service as a result of the Contingency. Furthermore, in limited
circumstances Demand may need to be interrupted to address BES performance requirements. When
interruption of Demand is utilized within the planning process to address BES performance requirements, such
interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is

Dra ft 3: No ve m b e r 4, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Dra ft 3: No ve m b e r 4, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

Dra ft 23: Au g u s t 30No ve m b e r 4, 2010

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

Dra ft 23: Au g u s t 30No ve m b e r 4, 2010

Page 3 of 6

S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of
interruption of Demand following Contingency events. Interruption of Demand is discouraged and measures to
mitigate such interruption should be pursued within the planning process. However, it is recognized that
Demand may need to will be interrupted if it is directly served by the Elements removed from service as a result
of the Contingency. Furthermore, in limited circumstances Demand may need to be interrupted to address BES
performance requirements. When interruption of Demand is utilized within the planning process to address
BES performance requirements, such interruption is limited to:

o

Demand that is directly served by the elements that are removed from service as a result of the
Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the cCircumstances
describing where the uses of such Demand interruption are documented, including alternatives
evaluated; and where the application Demand interruption is subject to review and acceptance in an
open and transparent stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.

Dra ft 23: Au g u s t 30No ve m b e r 4, 2010

Page 5 of 6

S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Dra ft 23: Au g u s t 30No ve m b e r 4, 2010

Page 6 of 6

S ta n d a rd TP L-001-01 — S ys te m P e rfo rm a n ce Un d e r No rm a l Co n d itio n s

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-01

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:

April 1, 2005

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.

Adopted by NERC Board of Trustees: February 8, 2005
Page 1 of 7
Effective Date: April 1, 2005

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S ta n d a rd TP L-001-01 — S ys te m P e rfo rm a n ce Un d e r No rm a l Co n d itio n s

R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.
R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-01_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures

Adopted by NERC Board of Trustees: February 8, 2005
Page 2 of 7
Effective Date: April 1, 2005

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S ta n d a rd TP L-001-01 — S ys te m P e rfo rm a n ce Un d e r No rm a l Co n d itio n s

M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-0_R2.1_R1 and TPL001-0_1_ R2.2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Timeframe
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

July 24, 2007

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

Errata

Adopted by NERC Board of Trustees: February 8, 2005
Page 3 of 7
Effective Date: April 1, 2005

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S ta n d a rd TP L-001-01 — S ys te m P e rfo rm a n ce Un d e r No rm a l Co n d itio n s

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

Adopted by NERC Board of Trustees: February 8, 2005
Page 4 of 7
Effective Date: April 1, 2005

Dra ft 3: No ve m b e r 4, 2010

S ta n d a rd TP L-001-0 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Category

Contingencies

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005Draft 3: November 4, 2010

5 of 5

S ta n d a rd TP L-001-0 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of
Demand following Contingency events. However, it is recognized that Demand will be interrupted if it is
directly served by the Elements removed from service as a result of the Contingency. Furthermore, in limited
circumstances Demand may need to be interrupted to address BES performance requirements. When
interruption of Demand is utilized within the planning process to address BES performance requirements, such
interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005Draft 3: November 4, 2010

5 of 5

S ta n d a rd TP L-001-0 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005Draft 3: November 4, 2010

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Informal comment period completed October 8, 2010.
Proposed Action Plan and Description of Current Draft:
This is the third draft of the proposed modification to footnote ‘b’ posted for a 45-day formal
comment period, with an initial ballot to be conducted during the last 10 days of the comment
period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial ballot

December 2010

2. Recirculation ballot

January 2011

3. Submit to BOT for approval

January 2011

4. File with FERC

February 2011

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Draft 3: November 4, 2010

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Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to:
o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of interruption of
Demand following Contingency events. Interruption of Demand is discouraged and measures to mitigate such
interruption should be pursued within the planning process. However, it is recognized that Demand may need to will be
interrupted if it is directly served by the Elements removed from service as a result of the Contingency. Furthermore, in
limited circumstances Demand may need to be interrupted to address BES performance requirements. When interruption
of Demand is utilized within the planning process to address BES performance requirements, such interruption is limited
to:
o

Demand that is directly served by the elements that are removed from service as a result of the
Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the cCircumstances
describing where the uses of such Demand interruption are documented, including alternatives
evaluated; and where the application Demand interruption is subject to review and acceptance in an
open and transparent stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
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f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-01b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:

April 1, 2005

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

Adopted by NERC Board of Trustees: February 8, 2005
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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-01_R1 and TPL-002-01_R2.

Adopted by NERC Board of Trustees: February 8, 2005
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Effective Date: April 1, 2005

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Table I. Transmission System Standards — Normal and Emergency Conditions
Adopted by NERC Board of Trustees: February 8, 2005
Page 3 of 11
Effective Date: April 1, 2005

Draft 3: November 4, 2010

S ta n d a rd TP L-002-01b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005
Page 4 of 11
Effective Date: April 1, 2005

Draft 3: November 4, 2010

S ta n d a rd TP L-002-0b 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to:
o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.

Draft 3: November 3, 2010

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S ta n d a rd TP L-002-0b 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 3: November 3, 2010

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S ta n d a rd TP L-002-0b 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Draft 3: November 3, 2010

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Draft 3: November 3, 2010

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Draft 3: November 3, 2010

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005Draft 3: November 4, 2010

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misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk
Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: April 1, 2005Draft 3: November 4, 2010

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Informal comment period completed October 8, 2010.
Proposed Action Plan and Description of Current Draft:
This is the third draft of the proposed modification to footnote ‘b’ posted for a 45-day formal
comment period, with an initial ballot to be conducted during the last 10 days of the comment
period.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial ballot

December 2010

2. Recirculation ballot

January 2011

3. Submit to BOT for approval

January 2011

4. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

Draft 3: November 4, 2010

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 3: November 4, 2010

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives evaluated; and
where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

Draft 23: August 30November 3, 2010

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of interruption of
Demand following Contingency events. Interruption of Demand is discouraged and measures to mitigate such
interruption should be pursued within the planning process. However, it is recognized that Demand may need to will be
interrupted if it is directly served by the Elements removed from service as a result of the Contingency. Furthermore, in
limited circumstances Demand may need to be interrupted to address BES performance requirements. When interruption
of Demand is utilized within the planning process to address BES performance requirements,, such interruption is limited
to:

o

Demand that is directly served by the elements that are removed from service as a result of the Contingency

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the cCircumstances describing where
the uses of such Demand interruption are documented, including alternatives evaluated; and where the
application Demand interruption is subject to review and acceptance in an open and transparent stakeholder
process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

Draft 23: August 30November 3, 2010

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 23: August 30November 3, 2010

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Draft 23: August 30November 3, 2010

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-01a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:

April 1, 2005

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.

Adopted by NERC Board of Trustees: February 8, 2005
Page 1 of 9
Effective Date: April 1, 2005

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R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
Adopted by NERC Board of Trustees: February 8, 2005
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Effective Date: April 1, 2005

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M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-01_R1 and TPL-003-01_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Adopted by NERC Board of Trustees: February 8, 2005
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Effective Date: April 1, 2005

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S ta n d a rd TP L-003-01a — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f Two o r Mo re BES Ele m e n ts

Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005
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Effective Date: April 1, 2005

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of Demand interruption are documented, including alternatives evaluated; and
where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
Adopted by NERC Board of Trustees: February 8, 2005
Page 5 of 9
Effective Date: April 1, 2005

Draft 3: November 4, 2010

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 2005
Page 6 of 9
Effective Date: April 1, 2005

Draft 3: November 4, 2010

S ta n d a rd TP L-003-01a — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f Two o r Mo re BES Ele m e n ts

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Adopted by NERC Board of Trustees: February 8, 2005
Page 7 of 9
Effective Date: April 1, 2005

Draft 3: November 4, 2010

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Adopted by NERC Board of Trustees: February 8, 2005
Page 8 of 9
Effective Date: April 1, 2005

Draft 3: November 4, 2010

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Adopted by NERC Board of Trustees: February 8, 2005
Page 9 of 9
Effective Date: April 1, 2005

Draft 3: November 4, 2010

S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

Draft 3: November 4, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

Draft 3: November 4, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Draft 3: November 4, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 3: November 4, 2010

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S ta n d a rd TP L-004-0a — S ys te m P e rfo rm a n c e Fo llowin g Extre m e BES Eve n ts

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of such Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent stakeholder
process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.
Draft 3: November 4, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

Draft 23: November 4August 30, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

Draft 23: November 4August 30, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Draft 23: November 4August 30, 2010

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S ta n d a rd TP L-004-1 — S ys te m P e rfo rm a n c e Fo llowin g Extrem e BES Eve n ts
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 23: November 4August 30, 2010

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S ta n d a rd TP L-004-0a — S ys te m P e rfo rm a n c e Fo llowin g Extre m e BES Eve n ts

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to avoid should be to minimize the likelihood and magnitude of interruption of
Demand following Contingency events. Interruption of Demand is discouraged and measures to mitigate such
interruption should be pursued within the planning process. However, it is recognized that Demand may need towill be
interrupted if it is directly served by the Elements removed from service as a result of the contingency. Furthermore, in
limited circumstances Demand may need to be interrupted to address BES performance requirements. When interruption
of Demand is utilized within the planning process to address BES performance requirements, such interruption is limited
to:

o

Demand that is directly served by the elements that are removed from service as a result of the Contingency,
or

o

Interruptible Demand or Demand-Side Management

o

Demand that does not adversely impact overall BES reliability where the cCircumstances describing where
the uses of such Demand interruption are documented, including alternatives evaluated; and where the
application Demand interruption is subject to review and acceptance in an open and transparent stakeholder
process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
Draft 32: August 30November 4, 2010

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 32: August 30November 4, 2010

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S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-01

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:

April 1, 2005

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
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S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-01_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-01_R1.
D. Compliance
1.

2.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
2 of 6
Effective Date: April 1, 2005

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
2.4.
B.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
3 of 6
Effective Date: April 1, 2005

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
4 of 6
Effective Date: April 1, 2005

S ta n d a rd TP L-004-00a — S ys te m P e rfo rm a n c e Fo llo win g Extre m e BES Eve n ts

D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of Demand
following Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the contingency. Furthermore, in limited circumstances Demand may need
to be interrupted to address BES performance requirements. When interruption of Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:

o

Interruptible Demand or Demand-Side Management

o

Circumstances where the uses of such Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent stakeholder
process that includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
5 of 6
Effective Date: April 1, 2005

S ta n d a rd TP L-004-00a — S ys te m P e rfo rm a n c e Fo llo win g Extre m e BES Eve n ts

e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 2005Draft 3: November 4, 2010
6 of 6
Effective Date: April 1, 2005

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)
Please DO NOT use this form to submit comments on the 3rd posting for Project 2010-11:
TPL Table 1 Order. Please use the electronic comment form posted on the following project
page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
The electronic comment form must be completed by January 5, 2011. This is a 45-day
formal comment period.
If you have questions please contact Ed Dobrowolski at [email protected] or by
telephone at 609-947-3673.

Background Information
The Standard Drafting Team (SDT) posted Table I, footnote ‘b’ for an informal comment
period from September 8, 2010 through October 8, 2010. Industry response was divided in
relation to support for the proposed footnote ‘b.’ Although there were a number of
supporters for the proposed footnote they were outnumbered by the commenters who did
not support the footnote text for various reasons and offered their views and concerns.
The SDT carefully considered the feedback provided including minority opinions such as not
allowing Demand interruption at all and has made clarifying revisions to the footnote ‘b’
text.
The revisions made to footnote ‘b’ following the informal comment period are shown below:
b) An objective of the planning process is to avoid should be to minimize the likelihood and
magnitude of interruption of Demand following Contingency events. Interruption of
Demand is discouraged and measures to mitigate such interruption should be pursued
within the planning process. However, it is recognized that Demand may need to will be
interrupted if it is directly served by the elements removed from service as a result of
the Contingency. Furthermore, in limited circumstances Demand may need to be
interrupted to address BES performance requirements. When interruption of Demand is
utilized within the planning process to address BES performance requirements, such
interruption is limited to:
• Demand that is directly served by the elements that are removed from service as a
result of the Contingency
• Interruptible Demand or Demand-Side Management
• Demand that does not adversely impact overall BES reliability where the
cCircumstances describing where the use of such Demand interruption are
documented, including alternatives evaluated; and where the application Demand
interruption is subject to review and acceptance in an open and transparent
stakeholder process that includes addressing stakeholder comments.

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

Unofficial Comment Form for TPL Table 1 Order (Project 2010-11)

Please Enter All Comments in Simple Text Format.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with a FERC
directive which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding
the planned or controlled interruption of electric supply where a single contingency
occurs on a transmission system. Do you agree with the proposed changes and if not,
please provide specific reasons for your disagreement.
Yes
No
Comments:

2

 

Standards Announcement

Initial Ballot Open December 27, 2010 – January 5, 2011
Now available at: :  https://standards.nerc.net/CurrentBallots.aspx
TPL Table 1, Footnote B SAR (Project 2010-11)
An initial ballot is open on Table 1 footnote ‘b’ in TPL-001-1 through TPL-004-1 until 8 p.m.
EDT on January 5, 2011.
FERC’s Order in docket RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1- footnote
‘b,’ regarding the planned or controlled interruption of electric supply, where a single
contingency occurs on a transmission system, and originally directed NERC to file the revised
standards by June 30, 2010. To meet this directive, a proposed revision was posted for “Urgent
Action” and balloted from May 17-27, 2010. The proposed revision achieved a quorum (84%)
and almost enough affirmative votes (64%) to achieve weighted segment approval; however,
many balloters provided comments indicating the need for additional modifications. Following
the initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer
considered “Urgent Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected
in all four standards:
 TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category
A)


TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System
Element (Category B)



TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)



TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of
Two or More Bulk Electric System Elements (Category D)

Comment Period (through January 5, 2011)
A formal, 45-day comment period began on November 19, 2010 and will conclude when the
ballot closes on January 5, 2011. Please use this electronic form to submit comments. If you
experience any difficulties in using the electronic form, please contact Monica Benson at
[email protected]. An off-line, unofficial copy of the comment form is posted on the
project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html

Next Steps
The drafting team will consider all comments (those submitted with a comment form, and those

submitted with a ballot) and will determine whether to make additional changes to the standards.
The team will post its response to comments and, if the standards have only minor changes, will
post the standards and conduct a 10-day recirculation ballot.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate. 
   

For more information or assistance, please contact Monica Benson at [email protected].

North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

 

Standards Announcement
Ballot Pool Open November 19 – December 22, 2010
Comment Period Open November 19 – January 5, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
TPL Table 1, Footnote B SAR (Project 2010-11)
The TPL Table 1 Order Drafting Team is seeking comments on Table 1 footnote ‘b’ in TPL-001-1 through
TPL-004-1 until 8 p.m. EDT on January 5, 2011.
FERC’s Order in docket RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1- footnote ‘b,’ regarding
the planned or controlled interruption of electric supply, where a single contingency occurs on a transmission
system, and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive, a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision
achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however, many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer considered “Urgent
Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
• TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)
•

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category
B)

•

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

•

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More
Bulk Electric System Elements (Category D)

Ballot Pool (through December 22, 2010)
Because of the length of time between the last ballot (May 2010) and the time of the upcoming ballot
(December 2010, many members of the initial ballot pool are no longer in the Registered Ballot Body. The
existing ballot pool has been dissolved and a new ballot pool is being formed to vote on the proposed revision
to Table 1, footnote ‘b.’ Registered Ballot Body members may join this new ballot pool to be eligible to vote on
these proposed modifications until 8 a.m. EDT on December 22, 2010.
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: bp-2010-11_TPL_Table_1_in

Comment Period (through January 5, 2011)
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:

http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Next Steps
An initial ballot will be conducted during the last 10 days of the formal comment period. The drafting team will
consider all comments (those submitted with a comment form, and those submitted with a ballot) and will
determine whether to make additional changes to the standards. The team will post its response to comments
and, if the standards have only minor changes, will post the standards and conduct a 10-day recirculation ballot.

Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Ballot Pool Open November 19 – December 22, 2010
Comment Period Open November 19 – January 5, 2011
Now available at: http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
TPL Table 1, Footnote B SAR (Project 2010-11)
The TPL Table 1 Order Drafting Team is seeking comments on Table 1 footnote ‘b’ in TPL-001-1 through
TPL-004-1 until 8 p.m. EDT on January 5, 2011.
FERC’s Order in docket RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1- footnote ‘b,’ regarding
the planned or controlled interruption of electric supply, where a single contingency occurs on a transmission
system, and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive, a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision
achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however, many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer considered “Urgent
Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
• TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)
•

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category
B)

•

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

•

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More
Bulk Electric System Elements (Category D)

Ballot Pool (through December 22, 2010)
Because of the length of time between the last ballot (May 2010) and the time of the upcoming ballot
(December 2010, many members of the initial ballot pool are no longer in the Registered Ballot Body. The
existing ballot pool has been dissolved and a new ballot pool is being formed to vote on the proposed revision
to Table 1, footnote ‘b.’ Registered Ballot Body members may join this new ballot pool to be eligible to vote on
these proposed modifications until 8 a.m. EDT on December 22, 2010.
During the pre-ballot window, members of the ballot pool may communicate with one another by using their
“ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from using the ballot
pool list servers.) The list server for this ballot pool is: bp-2010-11_TPL_Table_1_in

Comment Period (through January 5, 2011)
Please use this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the comment
form is posted on the project page:

http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Next Steps
An initial ballot will be conducted during the last 10 days of the formal comment period. The drafting team will
consider all comments (those submitted with a comment form, and those submitted with a ballot) and will
determine whether to make additional changes to the standards. The team will post its response to comments
and, if the standards have only minor changes, will post the standards and conduct a 10-day recirculation ballot.

Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Initial Ballot Results
Project 2010-11: TPL Table 1, Footnote B
Now available at: https://standards.nerc.net/Ballots.aspx
An initial ballot of Table 1 footnote ‘b’ in TPL-001-1 through TPL-004-1 ended on January 5, 2011. Voting
statistics are listed below, and the Ballot Results Web page provides a link to the detailed results:
Quorum: 90.42%
Approval: 83.33%
Background:
FERC Order RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1 - footnote ‘b,’ regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a transmission
system and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision
achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however, many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer considered “Urgent
Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
•

TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)

•

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category
B)

•

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

•

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More
Bulk Electric System Elements (Category D)

More details may be found on the project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Next Steps
The drafting team will consider all comments (those submitted with a comment form and those submitted with a
ballot) and will determine whether to make additional changes to the footnote in the four standards. The team

will post its response to comments and, if the footnote has only minor changes, will post the standards and
conduct a 10-day recirculation ballot.
Ballot Criteria
Approval requires both (1) a quorum, which is established by at least 75% of the members of the ballot pool
submitting either an affirmative vote, a negative vote, or an abstention, and (2) a two-thirds majority of the
weighted segment votes cast must be affirmative; the number of votes cast is the sum of affirmative and
negative votes, excluding abstentions and non-responses.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.

For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

NERC Standards

 

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User Name

Ballot Results

Ballot Name: Project 2010-11 TPL Table 1 Footnote B SAR_in

Password

Ballot Period: 12/27/2010 - 1/5/2011
Ballot Type: Initial

Log in

Total # Votes: 283

Register
 

Total Ballot Pool: 313
Quorum: 90.42 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
83.33 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
95
11
66
26
58
37
0
8
4
8
313

#
Votes

 
1
1
1
1
1
1
0
0.5
0.4
0.6
7.5

#
Votes

Fraction
 

64
5
46
17
40
25
0
5
4
6
212

Negative
Fraction

 
0.8
0.5
0.793
0.944
0.851
0.862
0
0.5
0.4
0.6
6.25

Abstain
No
# Votes Vote

 
16
5
12
1
7
4
0
0
0
0
45

 
0.2
0.5
0.207
0.056
0.149
0.138
0
0
0
0
1.25

 
6
1
5
6
4
3
0
1
0
0
26

9
0
3
2
7
5
0
2
0
2
30

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
APS
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy

Member
 
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Jason Shaver
Barbara McMinn
Robert D Smith
John Bussman
James Armke

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f6991528-c7ab-4583-8d76-551b01981ac1[1/11/2011 4:38:09 PM]

Ballot
 
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Abstain

Comments
 
View

View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Avista Corp.
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lincoln Electric System
Lone Star Transmission, LLC
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico

Scott Kinney
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Kevin L Howes

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

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Chang G Choi

Affirmative

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Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative

Robert Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg

Affirmative
Affirmative
Affirmative

Michael Moltane

Affirmative

Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

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Walter Kenyon
Michael Gammon
Stan T. Rzad
Larry E Watt
Doug Bantam
Julius Horvath
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Richard L. Koch

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain

Randy MacDonald

Negative

View

Negative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

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Raymond P Kinney
David H. Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Chifong L. Thomas
Colt Norrish
Ronald Schloendorn
John C. Collins
David Thorne
Larry D. Avery
Brenda L Truhe
Sammy Roberts
Laurie Williams

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f6991528-c7ab-4583-8d76-551b01981ac1[1/11/2011 4:38:09 PM]

Affirmative
Affirmative
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NERC Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

Public Service Electric and Gas Co.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Snohomish County PUD No. 1
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
APS
Arkansas Electric Cooperative Corporation
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Leesburg
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Hydro One Networks, Inc.
JEA

Kenneth D. Brown
John C. Allen
Tim Kelley
Robert Kondziolka
Linda Brown
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Long T Duong
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Keith V. Carman
John Tolo
Jonathan Appelbaum
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Steven Norris
Philip Huff
James V. Petrella
Robert Lafferty
Pat G. Harrington
Andy Butcher
Rebecca Berdahl
Andrew Gallo
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Phil Janik
Michelle A Corley
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Anthony L Wilson
R Scott S. Barfield-McGinnis
David L Kiguel
Garry Baker

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f6991528-c7ab-4583-8d76-551b01981ac1[1/11/2011 4:38:09 PM]

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Negative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

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NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5

Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Orlando Utilities Commission
Owensboro Municipal Utilities
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
LaGen
Modesto Irrigation District
Ohio Edison Company
Oklahoma Municipal Power Authority
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
 
AEP Service Corp.
Amerenue
APS
Avista Corp.
BC Hydro and Power Authority

Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Ballard Keith Mutters
Thomas T Lyons
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
James Leigh-Kendall
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
Hubert C. Young
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Richard Comeaux
Spencer Tacke
Douglas Hohlbaugh
Terri Pyle
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

John D. Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Edwin B Cano
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
Clement Ma

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Negative
Affirmative

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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain

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NERC Standards
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6

Black Hills Corp
Bonneville Power Administration
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions

George Tatar
Francis J. Halpin

Affirmative
Affirmative

Max Emrick

Affirmative

Alan Gale
Stephanie Huffman
Wilket (Jack) Ng
James B Lewis
Bob Essex
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Jack Cashin

Affirmative

Doug Ramey
Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Dennis Florom
S N Fernando
Christopher Schneider
Don Schmit
Gerald Mannarino
Tracy R Bibb
Michael K Wilkerson
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Wayne Lewis
Jerzy A Slusarz
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Richard Jones
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Melissa Kurtz
Martin Bauer P.E.
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Justin Thompson
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f6991528-c7ab-4583-8d76-551b01981ac1[1/11/2011 4:38:09 PM]

Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative

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Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Negative

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Affirmative
Abstain

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Negative
Abstain
Affirmative
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NERC Standards
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6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
9
9
10
10
10
10
10
10
10
10
 

Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
 
INTELLIBIND
JDRJC Associates
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
Oregon Public Utility Commission
Snohomish County PUD No. 1
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Texas Reliability Entity
Western Electricity Coordinating Council

Richard L. Montgomery
Thomas E Washburn
Silvia P Mitchell
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
James D. Hebson
Claire Warshaw
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons

Affirmative
Affirmative

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Peter H Kinney

Affirmative

David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Kevin Conway
Jim D. Cyrulewski
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain

Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Donald E. Nelson

Affirmative

Jerome Murray
William Moojen
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Stacy Dochoda
Larry D. Grimm
Louise McCarren

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

 

A New Jersey Nonprofit Corporation

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Affirmative
Affirmative

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Affirmative
 

Legal and Privacy  :  609.452.8060 voice  :  609.452.9550 fax  :  116-390 Village Boulevard  :  Princeton, NJ 08540-5721
Washington Office: 1120 G Street, N.W. : Suite 990 : Washington, DC 20005-3801

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Individual or group. (27 Responses)
Name (21 Responses)
Organization (21 Responses)
Group Name (6 Responses)
Lead Contact (6 Responses)
Question 1 (27 Responses)
Question 1 Comments (27 Responses)
Group
Arizona Public Service Company
Janet Smith
No
It is not clear whether both bullets under "footnote b" have to be met or only one of the two have to be met. It is
suggested that the standard be very clear about this.
Group
Northeast Power Coordinating Council
Guy Zito
No
There is concern with the use of the term Demand. It is unclear throughout the footnote whether or not the term
Demand includes Interruptible Demand or Demand-Side Management. It is suggested that interruption of Demand be
clarified to not include Interruptible Demand or Demand-Side Management to more clearly show the permitted use of
Load shedding. It is unclear whether the second bullet includes Demand which is interrupted by the elements removed
from service. Clarification should be made such that Demand which is interrupted by the elements removed from
service should not be included in this bullet. Language that mitigation of Load and/or Demand interruption should be
pursued within the planning process should be reinstated as reinforcement of a Transmission Providers’ planning
obligations to their load customers, and system operations. Footnote ‘b’ should be made to read as follows: b) An
objective of the planning process is to minimize the likelihood and magnitude of interruption of Load and/or Demand
following Contingency events. Interruption of Load and/or Demand is discouraged and all measures to mitigate such
interruption should be pursued within the planning process. However, it is recognized that Load and/or Demand will be
interrupted if it is directly served by the elements automatically removed from service by the Protection System as a
result of a Contingency. Furthermore, in extraordinary circumstances within the planning process Load and/or Demand
may need to be interrupted to address BES performance requirements. When interruption of Load and/or Demand is
utilized within the planning process to address BES performance requirements, such interruption is limited to: •
Circumstances where the use of Load and/or Demand interruption are documented, including alternatives evaluated;
and where the Load and/or Demand interruption is made available for review in an open and transparent stakeholder
process. If Load and/or Demand interruption is necessary, planning should indicate the amount needed, and not
specify how it would be obtained. What Load and/or Demand is interrupted is an operational decision. Additional
comments not included in the material listed for footnote ‘b’ on the Comment Form. In the paragraph below the bullets
in footnote ‘b’, confusion is introduced through the use of the term “firm Demand”. It is unclear how this is different than
the defined term “Firm Demand” and what the implications of the term “firm Demand” are. This footnote should not
discourage such adjustments which actually increase the reliability of service to end users. The last sentence of
footnote ‘b’ is unnecessary and should be deleted. It is never acceptable to cause reliability concerns in another area
while addressing your own.
Individual
Aaron Staley
Orlando Utilities Commission
No
The current language provides a balance between the end goal of reliablity (no load loss for B events) and the practical
constraint that project cost may outweigh the benefit. Two things are unclear though. Item one: The standard team
should clarify if the bullets under note B are intended to be an AND (both conditions met) or an OR (either condition
met). As currently written it is not clear. Item #2: The section under firm transfers is in conflict with the section above. If
Demand is being curtailed under the first or second bullet and it’s served by firm service then service should also be
curtailed, however as written any demand served by firm service could not be curtailed.
Individual
Greg Rowland
Duke Energy
Yes
The effective date in the Implementation Plan needs to be changed to match the Effective Date in the standards, in

order to clarify the allowed interruption of Non-consequential load before the new Footnote ‘b’ takes effect.
Individual
Si Truc PHAN
Hydro-Quebec TransÉnergie
Yes
Paragraph should be more clear as: b) An objective of the planning process should be to minimize the likelihood and
magnitude of interruption of Demand following Contingency events. However, it is recognized that Demand will be
interrupted if it is directly served by the Elements removed from service as a result of the Contingency. Furthermore, in
limited circumstances within the planning process, Demand may need to be interrupted to address BES performance
requirements. In such case : o Only Interruptible Demand or Demand-Side Management are allowed; o Circumstances
where the uses of Demand interruption is needed shall be documented, compared to alternatives, and reviewed in an
open and transparent stakeholder process that address stakeholder comments. Curtailment of firm transfers is allowed,
when coupled with the appropriate and necessary re-dispatch of resources where it can be demonstrated that this does
not result in the shedding of any firm Demand and that Facilities remain within applicable Facility Ratings, including
Facilities external to the Transmission Planner’s planning region when they are relied upon.
Group
SERC Planning Standards Subcommittee
Charles W. Long
No
The PSS agrees that the proposed language for footnote b provides some additional clarity. While we generally support
the concept, we have concerns that the phrase “is subject to review in an open and transparent stakeholder process
that includes addressing stakeholder comments” remains ambiguous and should be clarified by limiting stakeholder
input to those who have load at risk or local regulators obligated to act on their behalf. Revise the first sentence of the
last paragraph to read: “To prepare for a second contingency, curtailment of firm transfers is allowed, when coupled
with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand.” The
comments expressed herein represent a consensus of the views of the above-named members of the SERC EC
Planning Standards Subcommittee only and should not be construed as the position of SERC Reliability Corporation,
its board, or its officers.
Individual
Tim Ponseti, VP
TVA Trasnmission Plannning & Compliance
No
TVA appreciates the SDT’s efforts to clarify and improve this complex and challenging area. However, as mentioned in
our last comments regarding footnote b, TVA still believes that the SDT’s proposal is still focusing more on reliability of
local loads than on the overall reliability of the BES. Reliability of local loads should be addressed outside the TPL
standards and therefore should not be used/referenced in footnote b. Existing stakeholder processes (referred to in the
SDT proposal) typically focus on larger system issues and not on local load serving. TVA believes that some local load
should be allowed to be dropped in order to maintain BES reliability. Instead of the proposed footnote b, TVA suggests
that the SDT define a “local area” with guidelines detailing the reliability requirements for these local area loads. This
would separate the local area load requirements from the BES requirements in the TPL standards.
Individual
Alex Rost
New Brunswick System Operator
No
NBSO agrees with the principles of the current version of the proposed footnote, as far as NBSO’s interpretation of the
footnote is correct. NBSO has the following detailed comments: 1. The first paragraph contains many general
statements that attempts to capture essential planning principles. NBSO feels that such language is not suited for a
footnote. NBSO suggests re-wording of the first paragraph to state: Interruption of Demand may be utilized within the
planning process to address BES performance requirements. Such cases are limited to: NBSO also suggests turning
the phrase that addresses Demand lost that was served by elements removed from service as a result of a
Contingency into a bullet item. NBSO feels that this adds clarity since all of the acceptable instances of Demand
interruption are now listed as bulleted items. 2. NBSO interprets that the currently proposed footnote allows for the two
bulleted options to be used exclusively or in combination. Thus for clarification NBSO suggests adding “or” after each
bulleted item, with the exclusion of the final bulleted item. 3. NBSO suggests removing the last sentence of the last
paragraph. Likely all industry members understand that causing reliability concerns in other areas is never acceptable.
This principle is not limited to the standard in question, and thus such a statement could require the update of other
standards. 4. NBSO interprets that the use of the word “Demand” in the second bullet of the proposed footnote is
referring to use of Firm Demand since the first bullet covers the other types of Demand (Demand = Firm Demand +
Interruptible Demand). As such NBSO suggests replacing “Demand” with “Firm Demand” in the second bullet. 5. NBSO

feels that the statement “that includes addressing stakeholder comments” should be removed from the last phrase of
the second bullet. An open and transparent stakeholder process should adequately address stakeholder comments
and concerns. Explicitly specifying that all stakeholder comments be addressed may add undue burden if the word
“address” is misconstrued. The task of addressing stakeholder comments is more appropriately addressed and defined
in each area’s respective process. 6. NBSO suggests replacing the word “shedding” with “interruption” in the last
phrase of the last paragraph to remain consistent with the rest of the proposed footnote. NBSO also suggests
capitalizing “firm” in the term “Firm Demand” to remain consistent with the NERC glossary of terms. 7. There is no term
“transfers” in the NERC glossary of terms. Perhaps some other defined term from the glossary could be used in lieu of
“transfers” (e.g. Firm Transmission Service). Taking into account the NBSO comments, the footnote could read as
follows: b) Interruption of Demand may be utilized within the planning process to address BES performance
requirements. Such cases are limited to: -Demand directly served by Elements removed from service as a result of a
Contingency, or -Use of Interruptible Demand or Demand-Side Management, or -Interruption of Firm Demand when
acceptable circumstances for such interruptions are documented (including alternatives evaluated), and where the Firm
Demand interruption is subject to review in an open and transparent stakeholder process. Curtailment of Firm
Transmission Service is allowed when coupled with the appropriate re-dispatch of resources obligated to do so, and it
can be demonstrated that Facilities remain within applicable Facility Ratings and there is no additional interruption of
Firm Demand.
Individual
Joe Petaski
Manitoba Hydro
No
The last bullet should be made clearer by adding the words “in jurisdictions” before the word “where”. Not all
jurisdictions are mandated to have a stakeholder process, so the standard should be clearly written to recognize this
situation. "Circumstances where the use of Demand interruption are documented, including alternatives evaluated; and
IN JURISDICTIONS where the Demand interruption is subject to review in an open and transparent stakeholder
process that includes addressing stakeholder comments."
Group
PacifiCorp
Sandra Shaffer
Yes
appreciates the efforts of the SDT and supports revision of TLP-002-0 Table 1 footnote “b” as stated in this draft.
Individual
Bernie Pasternack
Transmission Strategies, LLC
Yes
Individual
Michael A. Curtis, General Counsel
Mohave Electric Cooperative
Yes
Group
MRO's NERC Standards Review Subcommittee
Carol Gerou
Yes
Individual
David Thorne
Pepco Holding Inc
Yes
Individual
John Sullivan
Ameren
No
We agree with the statement that an objective of the planning process should be to minimize the likelihood and
magnitude of interruption of Demand following single contingency events. While we appreciate the drafting team’s

efforts in removing the need for acceptance by other parties in the stakeholder process, we still feel that language in
the second bullet of the revised footnote b should be modified to remove all references to an open and transparent
stakeholder process. Existing RTO stakeholder processes that we are aware of focus on larger system issues, rather
than on local load serving issues. Therefore, we believe that the load serving issues following single contingency
events are issues between the customer and the utility, and should be addressed in one-on-one forums between those
entities.
Individual
Thad Ness
American Electric Power
Yes
Individual
Bob Casey
Georgia Transmission Corporation
Yes
Individual
Alice Ireland
Xcel Energy
No
As this is currently drafted, planners would be required to host a forum with stakeholders to discuss hypothetical
actions that may be taken in an emergency. We do not see the value in this, nor is it clear who would be considered
stakeholders that should attend this forum. For example, we assume it would be the transmission owner’s meeting with
distribution providers to discuss the possibility of load shedding. Would that be adequate? Xcel Energy is both a
Transmission Planner and a Distribution Provider. In this case would the stakeholder be the end user? This should be
struck or more clearly defined.
Individual
Saurabh Saksena
National Grid
No
National Grid supports the direction the drafting team has taken. However, it has a few concerns with the language of
the footnote as amended. 1. Use of the term “Demand”: In the first sentence, it is unclear whether the term Demand
includes Interruptible Demand and Demand-Side Management. It is suggested that interruption of Demand be clarified
to exclude Interruptible Demand or Demand-Side Management. 2. It is unclear whether the second bullet includes
Demand which is interrupted by the elements removed from service. Clarification should be made such that Demand
which is interrupted by the elements removed from service should not be included in this bullet. 3. National Grid also
suggests changing “Demand interruption” to “interruption of Demand” in second bullet under “b)” to avoid awkward and
incorrect phasing. 4. ‘Addressing stakeholder comments’ introduces undefined actions which may be required in
response to the comments. If ‘Demand interruption is subject to review in an open and transparent stakeholder
process’, then stakeholder comments will be addressed without creating an undefined commitment to require it. As a
result, “that includes addressing stakeholder comments” should be deleted. 5. The second paragraph seems to be
restricting the use of Demand interruption for the sake of Firm Transfer reduction. This can be stated directly without
adding the confusion of re-dispatch. By coupling re-dispatch with a constraint of not shedding Demand, the paragraph
also creates confusion as to what to do in a situation where the amount of Demand that is allowed to be shed in the
first paragraph could be reduced with re-dispatch. Would re-dispatch not be allowed? National Grid suggests that the
paragraph be rewritten as follows: ‘Curtailment of firm transfers is allowed to meet BES performance requirements and
meet applicable Facility Ratings, where it can be demonstrated it does not result in the interruption of any Demand
(other than Interruptible Demand or Demand Side Management).’ 6. National Grid seeks clarification if there is an
intended distinction between the use of the term “firm Demand” and the defined term “Firm Demand” or is that just a
typo? 7. The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause
reliability concerns in another area while addressing your own. This same thought would have to be added to multiple
NERC standards if it were added here, otherwise it would infer that such actions are acceptable in all other standards.
Individual
Andrew Z. Pusztai
American Transmission Company
Yes
Individual
Jason L. Marshall

Midwest ISO
Yes
Group
Southern Company
Andy Tillery
No
Southern Company is voting "no" on the footnote b ballot because of concerns that the reliability of firm transfers could
be compromised. The existing Table I Transmission System Standards, which have been in place as early as the 1997
NERC Planning Standards, do not allow Loss of Demand or Curtailed Firm Transfers under single (Category B)
contingencies. Footnote B addressed two areas: 1) the loss of radial or local network load, which Southern Company
agrees that the drafting team has appropriately clarified and 2) preparing for the next contingency, which Southern
Company does not agree has been appropriately clarified. Southern Company believes the proposed wording
"Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch" now allows for the curtailment of firm transfers for single contingencies, whereas Southern Company did not
believe this was previously permitted under the standards. Southern Company interprets the new language to allow a
planner to curtail firm transfers (generation) to address a single contingency. Southern Company interpreted the
original language to not permit the curtailment of firm transfers (generation) for a single contingency, but rather that a
planner would develop a suitable transmission reinforcement or other mitigation. Southern Company is concerned that
the proposed language could result in a degradation in the dependability of firm transfers impacting the reliability of
those customers who rely upon them. Southern Company agrees that a system reconfiguration including the redispatch
of generation is appropriate when preparing for a second contingency (Category C). Therfore, a distinction is needed
between what is allowed in response to a first contingency and what is allowed to be prepared for a second
contingency. The curtailment of firm transfers should not be allowed as a response to the first contingency. This
practice would undermine the concept of firm transfers. The curtailment of firm transfers should only be allowed in
footnote b as a system adjustment to be prepared for a second contingency. We propose the following to clarify that
curtailments are permitted only to prepare for the second contingency. "To prepare for the next contingency,
curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch".
Individual
Michael Lombardi
Northeast Utilities
No
The revised language of Footnote b suggests that non-consequential demand interruption (load that is not directly
served by the elements removed from service as a result of the contingency) could be used to mitigate reliability
concerns arising from NERC Category B contingency events (i.e., single element contingencies). This language seems
to encourage operational workarounds and adds burdens for operators of the system. NU believes this is not consistent
with planning a highly reliable bulk electric system and thus does not support this weaker language.
Individual
Dan Rochester
Independent Electricity System Operator
Yes
Individual
Gregory Campoli
New York Independent System Operator
No
Proposed revised footnote language: b) It is recognized that Demand will be interrupted if it is directly served by the
Elements removed from service as a result of the Contingency. When interruption of Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to: o Interruptible Demand or
Demand-Side Management o Circumstances where the uses of firm Demand interruption not directly interrupted by the
contingency are documented, including alternatives evaluated; and where the firm Demand interruption is subject to
review in an open and transparent stakeholder process. Curtailment of firm transfers is allowed, when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that Facilities remain within
applicable Facility Ratings and the re-dispatch does not result in the interruption of any firm Demand. Comments:
There are generic concerns with the footnote as amended that must be addressed. The first is the use of the term
“Demand”. It is very unclear throughout the footnote whether or not the term Demand includes Interruptible Demand or
Demand-Side Management. It is suggested that interruption of Demand be clarified to not include Interruptible Demand
or Demand-Side Management to more clearly show the permitted use of that option for load shedding. Further
confusion is introduced through the use of the term “firm Demand” in some locations. It is unclear how this is different

than the defined term “Firm Demand” and what the implications of the term “firm Demand” are. The first and third
sentences of the first paragraph are unnecessary and should be deleted. However, if they are to be retained, the first
sentence is unacceptable in its current state. In some instances, Interruptible Demand or Demand-Side Management
are utilized in lieu of transmission additions. These can be considered as acceptable mitigation and there is no
justification to minimize their use. Therefore some clarification to the term Demand in the first sentence must be made.
It is unclear whether the second bullet includes Demand which is interrupted by the elements removed from service.
Clarification should be made such that Demand which is interrupted by the elements removed from service should not
be included in this bullet. The second portion of the second bullet should be deleted as it is unncessary: “and where the
Demand interruption is subject to review in an open and transparent stakeholder process that includes addressing
stakeholder comments.” If this is to be retained, the very last portion should be deleted “that includes addressing
stakeholder comments”. The term “addressing” is unclear. This can be misconstrued to infer that plans must be
changed in response to stakeholder comments. This may be inappropriate and may be impossible if conflicting
comments are received. It may also create a new standard that all comments must be “addressed”, which may not be a
part of the stakeholder process across NERC’s footprint. The first sentence of the paragraph under the two bullets
seems to prevent a situation where a combination of re-dispatch and the interruption of Demand are utilized. This
restriction could prevent a situation where the use of re-dispatch decreases the amount of Demand which must be
interrupted. This footnote should not discourage such adjustments which actually increase the reliability of service to
end users. This same sentence also uses the term “shedding of firm Demand”. This should be replaced with “Demand
interruption” such that it is consistent with the second bullet; otherwise an unnecessary new term has been introduced.
The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause reliability
concerns in another area while addressing your own. This same thought would have to be added to multiple NERC
standards if it was added here, otherwise it would infer that such actions are acceptable in all other standards.
Individual
Kathleen Goodman
ISO New England Inc
No
The following comments are provided in regard to this proposal. The first and third sentences of the first paragraph are
unnecessary. While we agree with the concept, it is unclear as to how inclusion of these sentences in a standard
creates a measureable requirement. There are generic concerns with the footnote as currently proposed. The first is
the use of the term “Demand.” It is unclear whether the term Demand includes Interruptible Demand and Demand-Side
Management. It is suggested that interruption of Demand be clarified to exclude Interruptible Demand and DemandSide Management to more clearly show the permitted use of those options. The second concern is that it is unclear
whether the second bullet includes Demand which is interrupted by the elements removed from service. Clarification
should be made such that Demand which is interrupted by the elements removed from service should not be included
in this bullet. The third is that not all areas have stakeholder processes. Documenting the use of Demand Interruption
should be sufficient without requiring stakeholder review. Therefore the second portion of the second bullet “including
alternatives evaluated; and where the Demand interruption is subject to review in an open and transparent stakeholder
process that includes addressing stakeholder comments” is unnecessary and should be deleted. “Addressing
stakeholder comments” introduces undefined actions which may be required in response to the comments. For those
areas that already have stakeholder processes, stakeholder comments are by definition addressed. As a result, at a
minimum “that includes addressing stakeholder comments” should be deleted. Furthermore, for areas that do not have
stakeholder processes, so long as they publish their studies impacted parties are aware of the role of demand
response. The fourth is that the second paragraph seems to be restricting the use of Demand interruption for the sake
of Firm Transfer reduction. This can be stated directly without adding the confusion of re-dispatch. By coupling redispatch with a constraint of not shedding Demand, the paragraph also creates confusion as to what to do in a situation
where the amount of Demand that is allowed to be shed in the first paragraph could be reduced with re-dispatch.
Would re-dispatch not be allowed? We suggest that the paragraph be rewritten as follows: “Curtailment of firm transfers
is allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can be demonstrated
it does not result in the interruption of any Demand (other than Interruptible Demand or Demand Side Management).”
The fifth is if the term ‘firm demand’ survives the proposed changes; is there an intended distinction between the use of
the term “firm Demand” and the defined term “Firm Demand”? If these terms are intended to be differently, it is unclear
what the term “firm Demand” represents. The final comment is that the last sentence of footnote B is unnecessary and
should be deleted. It is never acceptable to cause reliability concerns in another area while addressing your own. This
same thought would have to be added to multiple NERC standards if it was added here, otherwise it would infer that
such actions are acceptable in all other standards. If the first and third sentences must be retained the following
wording for the footnote is proposed: b) An objective of the planning process should be to minimize the likelihood and
magnitude of interruption of Demand, (excluding Interruptible Demand or Demand-Side Management), following
Contingency events. However, it is recognized that Demand will be interrupted if it is directly served by the Elements
removed from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need to be
interrupted to address BES performance requirements. When interruption of Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to: o Interruptible Demand or DemandSide Management o Circumstances where the uses of Demand interruption not directly interrupted by the contingency
are documented. Curtailment of firm transfers is allowed to meet BES performance requirements and meet applicable
Facility Ratings, where it can be demonstrated it does not result in the interruption of any Demand (other than

Interruptible Demand or Demand Side Management).
Individual
Harold Wyble
Kansas City Power & Light
Yes

Consideration of Comments on Successive Ballot — Project 2010-11 – TPL Table 1, Footnote b
Successive Ballot Dates: 12/27/2010 - 1/5/2011
Summary Consideration:
The SDT reviewed all of the comments received and has made a clarifying change to the structure of the footnote to address industry concerns as to the intent of
the SDT. No contextual changes have been made to the footnote. Therefore, the SDT is recommending that this project be moved to a recirculation ballot.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is subject
to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
If you feel that the drafting team overlooked your comments, please let us know immediately. Our goal is to give every comment serious consideration in this
process. If you feel there has been an error or omission, you can contact the Vice President and Director of Standards, Herb Schrayshuen, at 609-452-8060 or at
1
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.

Balloter
Richard J.
Mandes
1

Company
Alabama Power
Company

Segment
3

Vote
Negative

Comment
Southern Company is voting "no" on the footnote b ballot because of concerns that the reliability
of firm transfers could be compromised. The existing Table I Transmission System Standards,

The appeals process is in the Reliability Standards Development Procedure: http://www.nerc.com/files/RSDP_V6_1_12Mar07.pdf.

Balloter
Anthony L
Wilson

Company
Georgia Power
Company

Segment
3

Vote

Comment

Negative

which have been in place as early as the 1997 NERC Planning Standards, do not allow Loss of
Demand or Curtailed Firm Transfers under single (Category B) contingencies. Footnote B
addressed two areas: 1) the loss of radial or local network load, which Southern Company agrees
Don Horsley
Mississippi Power
3
Negative
that the drafting team has appropriately clarified and 2) preparing for the next contingency, which
Southern Company does not agree has been appropriately clarified. Southern Company believes
the proposed wording "Curtailment of firm transfers is allowed, when coupled with the appropriate
Horace
Southern
1
Negative
re-dispatch of resources obligated to re-dispatch" now allows for the curtailment of firm transfers
Stephen
Company Services,
for single contingencies, whereas Southern Company did not believe this was previously permitted
Williamson
Inc.
under the standards. Southern Company interprets the new language to allow a planner to curtail
firm transfers (generation) to address a single contingency. Southern Company interpreted the
original language to not permit the curtailment of firm transfers (generation) for a single
contingency, but rather that a planner would develop a suitable transmission reinforcement or
other mitigation. Southern Company is concerned that the proposed language could result in a
degradation in the dependability of firm transfers impacting the reliability of those customers who
rely upon them. Southern Company agrees that a system reconfiguration including the redispatch
of generation is appropriate when preparing for a second contingency (Category C). Therfore, a
distinction is needed between what is allowed in response to a first contingency and what is
allowed to be prepared for a second contingency. The curtailment of firm transfers should not be
allowed as a response to the first contingency. This practice would undermine the concept of firm
transfers. The curtailment of firm transfers should only be allowed in footnote b as a system
adjustment to be prepared for a second contingency. We propose the following to clarify that
curtailments are permitted only to prepare for the second contingency. "To prepare for the next
contingency, curtailment of firm transfers is allowed, when coupled with the appropriate redispatch of resources obligated to re-dispatch".
Response: The SDT has changed the wording „coupled with‟ to „achieved through‟ to better clarify the SDT‟s intent.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand

2

Balloter

Company

Segment

Vote

Comment

interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
As drafted, footnote „b‟ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language recognizes
that System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be utilized for a
limited time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the Transmission Planner
can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not obligated to re-dispatch,
the firm transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the
footnote. No change made.
Jennifer
Ameren Energy
6
Negative
We agree with the statement that an objective of the planning process should be to minimize the
Richardson
Marketing Co.
likelihood and magnitude of interruption of Demand following single contingency events. While we
appreciate the drafting team‟s efforts in removing the need for acceptance by other parties in the
Kirit S. Shah
Ameren Services
1
Negative
stakeholder process, we still feel that language in the second bullet of the revised footnote b
should be modified to remove all references to an open and transparent stakeholder process.
Existing RTO stakeholder processes that we are aware of focus on larger system issues, rather
than on local load serving issues. Therefore, we believe that the load serving issues following
single contingency events are issues between the customer and the utility, and should be
addressed in one-on-one forums between those entities.
Response: The SDT disagrees that this should be handled through two party interactions. The SDT believes that in situations where an entity‟s planning
studies require the interruption of Firm Demand to remain within BES Facility Ratings that the entity needs to share those plans in an open and transparent
stakeholder process to ensure that other parties that may be impacted by those decisions have the ability to review those plans. No change made.
Steven Norris APS
3
Negative
It is not clear whether both bullets under “footnote b” have to be met or only one of the two have
to be met. It is suggested that the standard be very clear about this
Mel Jensen
APS
5
Negative
Robert D
Arizona Public
1
Negative
Smith
Service Co.
Response: The bullets – o Interruptible Demand or Demand-Side Management and o Circumstances where … are not requirements that must be met, but
rather they define the conditions, either one or both, where Load is allowed to be interrupted. The SDT has rearranged the footnote to clarify the intent of the
footnote.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved through the appropriate re-dispatch of resources obligated to re-dispatch,

3

Balloter

Company

Segment

Vote

Comment

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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
John Tolo
Tucson Electric
1
Negative
The first sentence of the second paragraph appears to conflict with the first paragraph in that it
Power Co.
indicates that curtailment of transfers is allowed under certain conditions as long as it doesn‟t
result in the shedding of any firm Demand. Language needs to be added to the end of the first
sentence of the second paragraph of Footnote B that clarifies that the shedding of firm Demand as
clarified in paragraph one of Footnote B is allowed.
Scott Kinney
Avista Corp.
1
Affirmative
The first sentence of the second paragraph appears to conflict with the first paragraph in that it
indicates that curtailment of transfers is allowed under certain conditions as long as it doesn‟t
Robert
Avista Corp.
3
Affirmative
result in the shedding of any firm Demand. Language needs to be added to the end of the first
Lafferty
sentence of the second paragraph of Footnote B that clarifies that the shedding of firm Demand as
clarified in paragraph one of Footnote B is allowed.
Brenda S.
Anderson

Bonneville Power
Administration

6

Affirmative

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.

William
Mitchell
Chamberlain

California Energy
Commission

9

Affirmative

I am voting for this improved standard but I am concerned that the first sentence of the second
paragraph appears to conflict with the first paragraph in that it indicates that curtailment of
transfers is allowed under certain conditions as long as it doesn‟t result in the shedding of any firm
Demand. This problem could be corrected by adding language to the end of the first sentence of
the second paragraph of Footnote B that clarifies that the shedding of firm Demand as clarified in
paragraph one of Footnote B is allowed.

4

Balloter

Company

Chang G Choi

1

Affirmative

5

Affirmative

James Tucker

City of Tacoma,
Department of
Public Utilities,
Light Division, dba
Tacoma Power
City of Tacoma,
Department of
Public Utilities,
Light Division, dba
Tacoma Power
Deseret Power

1

Affirmative

Chifong L.
Thomas

Pacific Gas and
Electric Company

1

Affirmative

James L.
Jones

Southwest
Transmission
Cooperative, Inc.

1

Affirmative

Travis
Metcalfe

Tacoma Public
Utilities

3

Affirmative

Max Emrick

Segment

Vote

Comment
Tacoma Power agrees that the revision is better than the existing language. However, to improve
clarity on the interrelationship of the 2 paragraphs of Footnote B, we strongly suggest adding the
following phrase to the end of the first sentence of the second paragraph, “unless the firm
Demand is allowed to be shed pursuant to the above paragraph in this footnote."

As drafted the first paragraph of proposed Footnote B identifies the objective of minimizing
interruption of Demand following Contingencies and goes on to identify the limited situation where
interruption of demand may be necessary. However, the first sentence of the second paragraph
appears to conflict with the first paragraph in that it indicates that curtailment of transfers is
allowed under certain conditions as long as it doesn‟t result in the shedding of any firm Demand.
Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed
PG&E supports the proposed footnote B. We believe, however, there is a potential for confusion
with the language as currently drafted. As drafted the first paragraph of proposed Footnote B
identifies the limited situations where interruption of demand may be necessary and would be
allowed. However, the first sentence of the second paragraph indicates that curtailment of
transfers is allowed under certain conditions as long as it doesn‟t result in the shedding of any firm
Demand. Taken together with the first paragraph, this requirement can be confusing because the
first paragraph potentially conflicts with the second paragraph. Please change the first sentence in
the second paragraph to read, "Curtailment of firm transfers is allowed, when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand, the interruption of which is otherwise allowed as described above.”
Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.
Tacoma Power agrees that the revision is better than the existing language. However, to improve
clarity on the interrelationship of the 2 paragraphs of Footnote B, we strongly suggest adding the
following phrase to the end of the first sentence of the second paragraph, “unless the firm
Demand is allowed to be shed pursuant to the above paragraph in this footnote.”

5

Balloter

Company

Segment

Vote

Comment

Keith
Morisette

Tacoma Public
Utilities

4

Affirmative

Michael C Hill

Tacoma Public
Utilities

6

Affirmative

Beth Young

Tampa Electric Co.

1

Affirmative

Ronald L
Donahey

Tampa Electric Co.

3

Affirmative

RJames
Rocha

Tampa Electric Co.

5

Affirmative

Benjamin F
Smith II

Tampa Electric Co.

6

Affirmative

Melissa Kurtz

U.S. Army Corps
of Engineers

5

Affirmative

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed.

Brandy A
Dunn

Western Area
Power
Administration

1

Affirmative

As drafted, the first paragraph of proposed Footnote B identifies the objective of minimizing
interruption of Demand following Contingencies and goes on to identify the limited situation where
interruption of demand may be necessary. However, the first sentence of the second paragraph
appears to conflict with the first paragraph in that it indicates that curtailment of transfers is
allowed under certain conditions as long as it doesn‟t result in the shedding of any firm Demand.
Western recommends that the Drafting Team include language at the end of the first sentence of
the second paragraph of Footnote B that clarifies that the shedding of firm Demand as clarified in
paragraph one of Footnote B is allowed.

Language needs to be added to the end of the first sentence of the second paragraph of Footnote
B that clarifies that the shedding of firm Demand as clarified in paragraph one of Footnote B is
allowed

Recommend adding language to paragraph 2, sentence 1 to clarify shedding of firm demand is
allowed as stated in Paragraph 1.

6

Balloter
Louise
McCarren

Company
Western Electricity
Coordinating
Council

Segment
10

Vote

Comment

Affirmative

WECC supports the concept that is clarified in the proposed language for Footnote B. We have
noted however, what could potentially be confusing language between paragraphs one and two of
the proposed language. Paragraph one correctly indicates that one of the objectives of
transmission planning is to minimize the likelihood and magnitude of interruption of Demand. The
first paragraph also recognizes that while this is an objective, there may be certain limited
conditions where Demand is interrupted. In recognizing this, the first paragraph lists those limited
instances when Demand may be interrupted. However, the first sentence of paragraph two could
be interpreted to mean that shedding of Firm Demand is not allowed. The sentence means that
shedding of Firm Demand is not allowed due to curtailment of firm transfers, but if there is a
situation where curtailment of firm transfers is necessary and curtailment of Demand per the
reasons listed in the first paragraph occurs, it should be clear that this is allowed. Suggest adding
the following language, or something similar, to the end of the first sentence of the second
paragraph of Footnote B. ...except as allowed above.
Response: The SDT has reorganized the footnote to clarify intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.

7

Balloter
Venkatarama
krishnan
Vinnakota

Company
BC Hydro

Segment
2

Vote
Negative

Comment
Footnote "b" of TPL-001/2/3/4 is still vague and not acceptable. The last paragraph of Footnote b
now reads: "Curtailment of firm transfers is allowed, when coupled with the appropriate redispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities remain
within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner‟s planning region are relied upon,
Facility Ratings in those regions would also be respected." We would like the SDT to answer the
following questions related to the paragraph quoted above:
1) What is meant by “firm transfers”? Is it simply energy flowing in real-time on Firm Transmission
Service (NERC defined term) that was not previously curtailed in the hour-ahead or day-ahead
scheduling processes, or does it refer to ALL Firm Transmission Service that was sold on a path?
2) Please provide an example of what an "appropriate re-dispatch of resources obligated to redispatch" could look like?
3) Assuming an outage of a single transmission line (N-1 Category B event) has occurred and
assuming that no "resources [are] obligated to redispatch" for this outage, would a transmission
provider be allowed to curtail Firm Transmission Service that it has sold in order to prepare to
withstand the next worst credible contingency?
4) Would transmission providers be allowed to sell Firm Transmission Service on a path above
what could be delivered with any one element of that path out of service across a range of
operating conditions?
5) If the proposed Footnote b is approved, and assuming an appropriate obligation to redispatch
could not be negotiated, would utilities have to reinforce their system (within 60 months) to ensure
that Firm Transmission Services already sold on particular paths would not be curtailed when any
one element of that path is out of service?
6) If a transmission provider employs Generation Dropping for single contingencies in order to
support Firm Transmission Service between regions, and assuming there are no provisions for
obligated re-dispatch, would the proposed Footnote b force a recalculation of firm vs non-firm
transfer capability?
7) Path 66 (PACI) and Path 65 (PDCI) can both see significant derates in their firm transfer
capability for single contingencies. How would the proposed Footnote b impact Firm Transmission
on these paths? Further, the Project 2010-11 SDT (Footnote “b”) should be amalgamated with the
Project No. 2006-02 SDT (TPL-001 through TPL004 amalgamation/update):
1. It doesn‟t make any sense to update Footnote “b” of TPL-001 based on the existing approved

8

Balloter

Company

Segment

Vote

Comment
version of TPL-001 when the language in that standard is being revised and terms that Footnote
“b” makes reference to will be changed. Draft #6 (2010-Oct-19) of TPL-001 has changed
“Footnote b” to “Footnote 9”.
2. Draft #6 of TPL-001 has changed the column heading relevant to “Footnote b” from “Loss of
Demand or Curtailed Firm Transfers” to “Interruption of Firm Transmission Service Allowed”.
3. Draft #6 of TPL-001 has seven new definitions including the following two definitions that would
be expected to be relevant to Footnote b: 3.1. Consequential Load Loss: All Load that is no longer
served by the Transmission system as a result of Transmission Facilities being removed from
service by a Protection System operation designed to isolate the fault. 3.2. Non-Consequential
Load Loss: Non-Interruptible Load loss that does not include: (1) Consequential Load Loss, (2) the
response of voltage sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.

4. The Project 2006-02 SDT has placed Draft #6 of TPL-001 on hold, stating, “The team will delay
moving the standard forward until the resolution of “footnote b” has become clear.”
Response: 1. For consistency with the existing standard text, the term „firm transfer‟ is retained. Therefore, the interpretation of “firm transfers” remains
unchanged.
2. One example would be a contractual arrangement that defines clear expectations to alternately serve Load upon the removal of the firm transfer so that no
loss of Load occurs.
3. In the planning timeframe, footnote „b‟ addresses single Contingencies (Cat. B) and footnote „c‟ addresses the Cat. C Contingencies. Neither footnote
prohibits System adjustments, which could include re-dispatch of your own resources to prepare for the next Contingency.
4. How Firm Transmission Service (FTS) is sold is addressed in individual tariffs in concert with the MOD standards.
5. The implementation plan provides 60 months after regulatory approval for entities to comply with the modified standard. How that is accomplished is up to
individual entities.
6. & 7 Each circumstance may need to be evaluated individually and additional documentation of understandings may be necessary.
7-1 - 4. Based on ballot comments and regulatory orders, the SDT determined that the best course of action was to address footnote „b‟ as a standalone item
and then incorporate the changes approved for footnote „b‟ into the new TPL-001-2 in a manner consistent with the other proposed changes in TPL-001-2.
Christopher L Consolidated
1
Negative
Interruptible Demand, like Demand-Side-Management, is an operational tool. We do not believe it
de
Edison Co. of New
appropriate to use operational tools for transmission planning. A load serving entity should not
Graffenried
York
claim to serve loads it plans to disconnect during a design contingency. In other words, these loads
should be excluded from the load forecast in the first place and, thereby, would not be represented
Peter T Yost
Consolidated
3
Negative
in power flows that are utilized to assess system performance under the TPL standards. This
Edison Co. of New
approach prevents the use of such load interruptions to address any deficiency found in TPL-type
York

9

Balloter

Company

Wilket (Jack)
Ng

Consolidated
Edison Co. of New
York

Segment
5

Vote
Negative

Comment
assessments.

Nickesha P
Carrol

Consolidated
6
Negative
Edison Co. of New
York
Response: Entities across the continent have many different Interruptible and Demand-Side Management programs that have many different attributes and
rules. Some entities have Interruptible Demand programs that are appropriate for planning purposes.
Chuck B
Manning

Electric Reliability
Council of Texas,
Inc.

2

Negative

The introductory paragraph of footnote b includes policy language. Since this is a reliability
standard-and not a policy directive-the general narrative setting forth the desired policy goal of
minimizing load-shedding is misplaced. Including policy language can cloud the specific issues the
standard attempts to address, and ERCOT recommends deleting the first two sentences in the
introductory paragraph.
The next sentence in the introductory paragraph goes on to state, generally, that demand may be
interrupted to "address BES performance requirements.” This phrase is vague. To which
performance requirements does this refer? The intent is not clear. If the intent is to generally
recognize the need to shed load to respect to NERC standards and to allow flexibility for an entity
to exercise discretion relative to meeting BES performance requirements, then that intent should
be clearly reflected in the language. Furthermore, the last sentence of the introductory paragraph
and the subsequent bullet points are arguably inconsistent with this approach, because they could
be viewed as removing an entity‟s flexibility/discretion by limiting the circumstances when load can
be shed.
The second bullet point is unnecessary, because it is already apparent that interruptible
demand/demand side management programs can be used according to their terms. This could
create confusion in that it could be implied that, absent the need to use these to meet BES
performance requirements, using them otherwise is inconsistent with/not allowed under footnote
b. Simply put, those products are not load shedding as contemplated by this footnote. Therefore
they should not be listed here.
With respect to the third bullet point, the phrase "demand that does not adversely impact overall
BES reliability" is not adequately defined, and provides opportunity for confusion. This is an
ambiguous phrase and can‟t be linked back to objective NERC standards/requirements. The bullet
points should avoid ambiguity to mitigate ambiguity risk in audits.

10

Balloter

Company

Segment

Vote

Comment
In addition, the last part of the language in this bullet imposing an open and transparent
stakeholder process is unclear. What is the intent behind requiring review in a stakeholder
process? If it is to establish the ability of the entity to develop load shedding procedures beyond
those explicitly contemplated in footnote b, ERCOT questions if it is reasonable for the responsible
entity to be required to get “permission” from stakeholders to implement reliability measures
related to its obligation as the functional entity. Again, the language simply is not clear.
Accordingly, ERCOT recommends this bullet point be removed. If it is retained, it should be revised
consistent with these comments to remove ambiguous language to mitigate potential confusion
around the meaning/scope of the footnote in the administration of the CMEP.
In addition, ERCOT recommends revising the draft footnote b to allow for planned Demand
interruption as a means of mitigation during interim periods when a unanticipated (such as
unexpected demand growth or unit retirements) or temporary change on the system occurs in a
timeframe that is shorter than the time necessary to plan and implement the system upgrades
necessary to avoid the Demand interruption.

Finally, in the last paragraph of footnote b, it isn‟t clear why “Transmission Service” was changed
to “transfers.” Firm transmission service is a service provided in some regions, and it provides
relative value to other types of services-e.g., non-firm and network. The mention of transmission
service may also be irrelevant in this footnote, since the allowance of its interruption doesn't also
allow for load shedding. Therefore, ERCOT recommends eliminating the last paragraph of footnote
b.
Response: The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to provide
a balance between flexibility and consistency across NERC. No change made.
The term “BES performance requirements” references the other requirements within the TPL standard and the SDT has removed the phrase “demand that does
not adversely impact overall BES reliability”.
In a previous posting, entities had stated that it was not clear that the use of Interruptible Load and Demand Side Management was permitted. The SDT added
this section to address those concerns. The SDT has reorganized and reformatted the footnote to improve clarity.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm

11

Balloter

Company

Segment

Vote

Comment

Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
The open and transparent process does not require “permission”, but rather it facilitates the open sharing of information between entities that have
responsibility for ensuring BES reliability.
The SDT decided to not limit the use of the footnote to a specific time period because there are circumstances where the longer term use may be implemented
without adversely impacting BES reliability.
For consistency with the existing standard text, the term „firm transfer‟ is retained. No change made.
Claudiu
GDS Associates,
1
Negative
We appreciate all the work conducted by SDT to adjust current footnote “b” however, we disagree
Cadar
Inc.
with the current approach mainly from the same reasons iterated during last comment period, as
follows:
• The definition does not go far enough with recognition that interruption of Demand should be
mitigated if at all possible. The language should encourage the TP to develop mitigation plans that
could be implemented as an alternative to Demand interruption.
• Use of Interruptible Demand should only be implemented if the Transmission Planner can point
to a contract between the Transmission Provider and Transmission Customer that permits load
curtailment.
• Under FERC Order 890, Conditional Firm transmission service can be granted for entities who
voluntarily acknowledge the right of the Transmission Provider to curtail their transaction or
provide re-dispatch. This should be the only transfer which can be utilized in the Planning Horizon
for interruption of Demand for Note b.
We suggest using the following wording as emphasized below: “An objective of the planning
process should be to minimize the likelihood and magnitude of interruption of Demand following
Contingency events and to develop mitigation plans that do not call for the curtailment of Demand.

12

Balloter

Company

Segment

Vote

Comment

It is recognized that Demand will be interrupted if it is directly served by the elements removed
from service as a result of the Contingency and in very limited circumstances when approaching
intermediate solutions to restore BES reliability. When interruption of Demand is utilized within the
planning process, such interruption is limited to:
? Demand that is directly served by the elements that are removed from service as a result of the
Contingency,
? Interruptible Demand or Demand-Side Management, where the Customer has given explicit
rights to the Transmission Provider for curtailment of their Demand,
? Demand, other than Interruptible Demand or Demand-Side Management, that does not
adversely impact overall BES reliability where the circumstances describing the use of such
Demand are documented, including alternatives evaluated; where the Load-Serving Entity who has
responsibility for serving such Demand has agreed to the curtailment, and where the application is
subject to review and acceptance in an open and transparent stakeholder process. Curtailment of
Firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch per the terms and conditions of the confirmed transmission service request between
the Transmission Customer and Transmission Provider, where it can be demonstrated that
Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the
shedding of any firm Demand. Where Facilities external to the Transmission Planner‟s planning
region are relied upon, Facility Ratings in those regions would also be respected. In addition, any
Conditional Firm transfers may be curtailed, in accordance with the terms and conditions of the
confirmed transmission service request between the Transmission Customer and Transmission
Provider.”
Response: In the footnote, the SDT has acknowledged that interrupting Firm Demand is not the preferred solution to BES concerns, while recognizing that this
may not always be possible. The SDT believes that the footnote as drafted strikes an appropriate balance. No change made.
It is well understood that there must be some agreement or contract before interruptible Demand or Demand-Side Management can be utilized by the planner.
The SDT disagrees that there should be a prohibition on utilizing other resources obligated to re-dispatch for Contingencies, unless it has been characterized as
“conditional firm”. Entities should not be restricted from utilizing other dispatch scenarios, as long as Firm Demand is not interrupted.
For the reasons stated above, the SDT has not modified the footnote as suggested.
Joe D Petaski Manitoba Hydro
1
Negative
The last bullet should be made clearer by adding the words “in jurisdictions” before the word
“where”. Not all jurisdictions are mandated to have a stakeholder process, so the standard should
Greg C.
Manitoba Hydro
3
Negative
be clearly written to recognize this situation. “Circumstances where the use of Demand interruption
Parent
are documented, including alternatives evaluated; and IN JURISDICTIONS where the Demand
S N Fernando Manitoba Hydro
5
Negative
interruption is subject to review in an open and transparent stakeholder process that includes
addressing stakeholder comments.”
Daniel
Manitoba Hydro
6
Negative

13

Balloter

Company

Segment

Vote

Comment

Prowse
Response: The SDT believes that if Firm Demand is planned to be interrupted utilizing footnote „b‟, there must be an open and transparent stakeholder
process to ensure that all parties that may be impacted have been notified and have an opportunity to provide comments. No change made.
Spencer
Tacke

Modesto Irrigation
District

4

Negative

I am voting NO on the proposed revision because the second bullet of the proposed revision is
nebulous as to how the exemption process will occur, and how it will be monitored by the auditors.

Also, the last sentence of the last paragraph of the proposed change is nebulous about keeping
facility flows within applicable Normal and Emergency thermal ratings. Thank you.
Response: Rather than mandate a one-size-fits-all process, the SDT has provided entities the latitude to utilize existing processes, modify existing processes,
or create new processes to provide an open and transparent stakeholder process. The SDT cannot comment on future actions of the auditors.
The SDT disagrees that maintaining Facilities within applicable Facility Ratings is a nebulous concept. That part of the footnote was included to ensure that the
plans to resolve a situation on a planner‟s System did not create other overloads. No change made.
Saurabh
National Grid
1
Negative
National Grid supports the direction the drafting team has taken. However, it has a few concerns
Saksena
with the language of the footnote as amended.
1. Use of the term “Demand”: In the first sentence, it is unclear whether the term Demand
includes Interruptible Demand and Demand-Side Management. It is suggested that interruption of
Demand be clarified to exclude Interruptible Demand or Demand-Side Management.
2. It is unclear whether the second bullet includes Demand which is interrupted by the elements
removed from service. Clarification should be made such that Demand which is interrupted by the
elements removed from service should not be included in this bullet.

14

Balloter
Michael
Schiavone

Company
Niagara Mohawk
(National Grid
Company)

Segment
3

Vote
Negative

Comment
3. National Grid also suggests changing “Demand interruption” to “interruption of Demand” in
second bullet under “b)” to avoid awkward and incorrect phasing.
4. „Addressing stakeholder comments‟ introduces undefined actions which may be required in
response to the comments. If „Demand interruption is subject to review in an open and transparent
stakeholder process‟, then stakeholder comments will be addressed without creating an undefined
commitment to require it. As a result, “that includes addressing stakeholder comments” should be
deleted.
5. The second paragraph seems to be restricting the use of Demand interruption for the sake of
Firm Transfer reduction. This can be stated directly without adding the confusion of re-dispatch. By
coupling re-dispatch with a constraint of not shedding Demand, the paragraph also creates
confusion as to what to do in a situation where the amount of Demand that is allowed to be shed
in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be allowed?
National Grid suggests that the paragraph be rewritten as follows: „Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can
be demonstrated it does not result in the interruption of any Demand (other than Interruptible
Demand or Demand Side Management).‟
6. National Grid seeks clarification if there is an intended distinction between the use of the term
“firm Demand” and the defined term “Firm Demand” or is that just a typo?

7. The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to
cause reliability concerns in another area while addressing your own. This same thought would
have to be added to multiple NERC standards if it were added here, otherwise it would infer that
such actions are acceptable in all other standards.
Response: 1. The SDT has reorganized the text in the footnote to address this concern.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:

15

Balloter

Company

Segment

Vote

Comment

Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
2. The SDT has reorganized the text in the footnote to address this concern.
3. The SDT believes that the proposed change does not add additional clarity to the footnote. No change made.
4. The SDT disagrees that each review process automatically will have a response to comments element. Therefore, the SDT added that element to ensure
that all stakeholder processes will include that element. No change made.
5. The SDT has reorganized the text in the footnote to address this concern.
6. The SDT has corrected the capitalization errors.
7. Since the planned action of curtailing of firm transfers may adversely impact neighboring systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. The SDT disagrees that an explicit statement in this footnote changes the intent of all other standards. No
change made.
Tony
Nebraska Public
3
Negative
NPPD votes NO due to the ambiguity of the terms “Curtailment of firm transfers is allowed, when
Eddleman
Power District
coupled the appropriate re-dispatch of resources” with respect to a Category B contingency event.
NPPD does not support the curtailment of firm transfers or re-dispatch to meet the performance
Don Schmit
Nebraska Public
5
Negative
requirements during a Category B (N-1) event. Curtailment of firm transfers and re-dispatch are
Power District
allowable following acceptable performance for the Category B (N-1) event, to get ready for the
next Category C type of event.
Response: As drafted, footnote „b‟ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language
recognizes that System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be
utilized for a limited time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the
Transmission Planner can plan to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not
obligated to re-dispatch, the firm transfers cannot be curtailed. No change made.

16

Balloter

Company

Randy
MacDonald

New Brunswick
Power
Transmission
Corporation

Segment
1

Vote
Negative

Comment
In general: NERC standards should not dictate circumstances or acceptable transmission
contingencies under which the tripping of customers loads is acceptable. That should be an issue
between the utility of supply, the customer, and the local regulating body so long as the
interruption to customers (for whatever contingency) is controlled and does not cause problems on
the BES, or to neighboring utilities.
Specifically, 1. The second bullet: The last sentence (following the semicolon) should be removed.
The local regulating body should provide input or approval.

2. NB Power Transmission interprets that the currently proposed footnote allows for the two
bulleted options to be used exclusively or in combination. Thus for clarification suggest adding “or”
after the first bulleted item.
Response: The SDT disagrees that this should be handled exclusively with the local regulating body. The SDT believes that in situations where an entity‟s
planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the entity needs to share those plans in an open and
transparent stakeholder process to ensure that other parties that may be adversely impacted by those decisions have the ability to review those plans. No
change made.
The SDT has reorganized the footnote to clarify its intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.

17

Balloter
Alden Briggs

Company
New Brunswick
System Operator

Segment
2

Vote
Negative

Comment
NBSO agrees with the principles of the current version of the proposed footnote assuming NBSO‟s
interpretation of the footnote is correct. NBSO has the following detailed comments: 1. The first
paragraph contains many general statements that attempts to capture essential planning
principles. NBSO feels that such language is not suited for a footnote. NBSO suggests re-wording
of the first paragraph to state: Interruption of Demand may be utilized within the planning process
to address BES performance requirements. Such cases are limited to:
NBSO also suggests turning the phrase that addresses Demand lost that was served by elements
removed from service as a result of a Contingency into a bullet item. NBSO feels that this adds
clarity since all of the acceptable instances of Demand interruption are now listed as bulleted
items.
2. NBSO interprets that the currently proposed footnote allows for the two bulleted options to be
used exclusively or in combination. Thus for clarification NBSO suggests adding “or” after each
bulleted item, with the exclusion of the final bulleted item.
3. NBSO suggests removing the last sentence of the last paragraph. Likely all industry members
understand that causing reliability concerns in other areas is never acceptable. This principle is not
limited to the standard in question, and thus such a statement could require the update of other
standards.
4. NBSO interprets that the use of the word “Demand” in the second bullet of the proposed
footnote is referring to use of Firm Demand since the first bullet covers the other types of Demand
(Demand = Firm Demand + Interruptible Demand). As such NBSO suggests replacing “Demand”
with “Firm Demand” in the second bullet.
5. NBSO feels that the statement “that includes addressing stakeholder comments” should be
removed from the last phrase of the second bullet. An open and transparent stakeholder process
should adequately address stakeholder comments and concerns. Explicitly specifying that all
stakeholder comments be addressed may add undue burden if the word “address” is misconstrued.
The task of addressing stakeholder comments is more appropriately addressed and defined in each
area‟s respective process.
6. NBSO suggests replacing the word “shedding” with “interruption” in the last phrase of the last
paragraph to remain consistent with the rest of the proposed footnote. NBSO also suggests
capitalizing “firm” in the term “Firm Demand” to remain consistent with the NERC glossary of
terms.

18

Balloter

Company

Segment

Vote

Comment
7. There is no term “transfers” in the NERC glossary of terms. Perhaps some other defined term
from the glossary could be used in lieu of “transfers” (e.g. Firm Transmission Service).

Taking into account the NBSO comments, the footnote could read as follows: b) Interruption of
Demand may be utilized within the planning process to address BES performance requirements.
Such cases are limited to: -Demand directly served by Elements removed from service as a result
of a Contingency, or -Use of Interruptible Demand or Demand-Side Management, or -Interruption
of Firm Demand when acceptable circumstances for such interruptions are documented (including
alternatives evaluated), and where the Firm Demand interruption is subject to review in an open
and transparent stakeholder process. Curtailment of Firm Transmission Service is allowed when
coupled with the appropriate re-dispatch of resources obligated to do so, and it can be
demonstrated that Facilities remain within applicable Facility Ratings and there is no additional
interruption of Firm Demand.
Response: 1 & 2. The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to
provide a balance between flexibility and consistency across NERC. The SDT has reorganized the footnote to clarify its intent and address the issue raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
3. Since the planned action of curtailing of firm transfers may adversely impact neighboring Systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. The SDT disagrees that an explicit statement in this footnote changes the intent of all other standards.
4. The SDT has reorganized the footnote to clarify its intent and address the issue raised.
5. The SDT believes that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the

19

Balloter

Company

Segment

Vote

Comment

entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those
decisions have the ability to review those plans. No change made.
6. The SDT does not believe that replacing the term shedding with interruption adds clarity and did not make the proposed change. The SDT has reorganized
the footnote to clarify its intent and address the second issue.
7. For consistency with the existing standard text, the term „firm transfer‟ is retained. No change made.
David H.
Northeast Utilities
1
Negative
The revised language of Footnote b suggests that non-consequential demand interruption (load
Boguslawski
that is not directly served by the elements removed from service as a result of the contingency)
could be used to mitigate reliability concerns arising from NERC Category B contingency events
(i.e., single element contingencies). This language seems to encourage operational workarounds
and adds burdens for operators of the system. NU believes this is not consistent with planning a
highly reliable bulk electric system and thus does not support this weaker language.
Response: The SDT believes that the language in this footnote is not weaker and does not encourage operational workarounds. The footnote language
provides the framework necessary to ensure that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES
Facility Ratings that the entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely
impacted by those decisions have the ability to review those plans. No change made.
Brad Chase
Orlando Utilities
1
Negative
“Two Items prevent us from voting yes. Item #1: The standard team should clarify if the bullets
Commission
under note B are intended to be an AND (both conditions met) or an OR (either condition met). As
currently written it is not clear.
Ballard Keith
Orlando Utilities
3
Negative
Mutters
Commission
Item #2: The section under firm transfers is in conflict with the section above. If Demand is being
curtailed under the first or second bullet and it‟s served by firm service then service should also be
curtailed, however as written any demand served by firm service could not be curtailed. Other then
these items the revisions does an excellent job of addressing the issue of load shedding under first
contingency conditions and practical reliablity.”
Response: The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management

20

Balloter

Company

Segment

Vote

Comment

Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Linda Brown

San Diego Gas &
Electric

1

Negative

Footnote b is a group of exceptions to the requirements for Category B contingencies. To add
clarity to the footnote, SDG&E would prefer that each exception be listed separately within the
footnote. As SDG&E understands the footnote, the following exceptions can occur after the loss of
a single element,
• Interruptible Demand can be used to unload a circuit, but the circuit(s) must remain below
emergency rating(s) at all times.
• Demand-Side Management can be used to unload a circuit, but the circuit(s) must remain below
emergency rating(s) at all times.
• Demand served by a radial element which is faulted may be interrupted.
• Curtailment of firm transfers is allowed, when coupled with re-dispatch of resources obligated to
re-dispatch.
SDG&E votes against the proposed language for the following reasons: SDG&E feels system
reliability alone should drive the need for a technical standard and the language of the standard
should reflect the need without reference to the process. FERC Order 890 set the forum for the
stakeholder process which provides commercial incentives and a level playing field for any
participant to build a transmission project. When considering compliance to the standards,
reference to “stakeholder process” is inappropriate and should be removed. Section 4 of the TPL
standards assigns responsibility for meeting the standards to the Planning Authority and the
Transmission Planner. These entities are subject to penalties if the requirement is not met. Use of
“stakeholder process” in the requirement implies that entities other than the Planning Authority or
the Transmission Planner have authority over how the standards are to be met without any
financial risk. If the “stakeholder process” language is not removed, SDG&E feels stakeholders
involved in the process should be registered with NERC and subject to the same audit
requirements and penalties as the Planning Authority or the Transmission Planner. Furthermore,
the California Transmission Owners have a FERC approved stakeholder process that is
administered by the California ISO. Addition of the term “stakeholder process” in a standard may
have unintended consequences.

21

Balloter

Company

Segment

Vote

Comment

Response: While the SDT believes that SDG&E proposed bullet list is consistent with the footnote as drafted, the list is not as inclusive as the footnote.
Therefore, the SDT has retained the existing text and reorganized the footnote for clarity.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
The SDT believes that in situations where an entity‟s planning studies require the interruption of Firm Demand to remain within BES Facility Ratings that the
entity needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those
decisions have the ability to review those plans. No change made.
Charles H
Southwest Power
2
Negative
The second paragraph of the footnote seems to be restricting the use of Demand interruption for
Yeung
Pool
the sake of Firm Transfer reduction. This can be stated directly without adding the confusion of redispatch. By coupling re-dispatch with a constraint of not shedding Demand, the paragraph also
creates confusion as to what to do in a situation where the amount of Demand that is allowed to
be shed in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be
allowed? We suggest that the paragraph be rewritten as follows: “Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can
be demonstrated it does not result in the interruption of any Demand (other than Interruptible
Demand or Demand Side Management).”
Response: The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved through the appropriate re-dispatch of resources obligated to re-dispatch,

22

Balloter

Company

Segment

Vote

Comment

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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Larry Akens
Tennessee Valley
1
Negative
TVA appreciates the SDT‟s efforts to clarify and improve this complex and challenging area.
Authority
However, as mentioned in our last comments regarding footnote b, TVA still believes that the
SDT‟s proposal is still focusing more on reliability of local loads than on the overall reliability of the
Ian S Grant
Tennessee Valley
3
Negative
BES. Reliability of local loads should be addressed outside the TPL standards and therefore should
Authority
not be used/referenced in footnote b. Existing stakeholder processes (referred to in the SDT
George T.
Tennessee Valley
5
Negative
proposal) typically focus on larger system issues and not on local load serving. TVA believes that
Ballew
Authority
some local load should be allowed to be dropped in order to maintain BES reliability. Instead of the
proposed footnote b, TVA suggests that the SDT define a “local area” with guidelines detailing the
Marjorie S.
Tennessee Valley
6
Negative
reliability requirements for these local area loads. This would separate the local area load
Parsons
Authority
requirements from the BES requirements in the TPL standards.
Response: The original footnote „b‟ focused on local area and limited interruption of Demand. Since individual entities planning philosophies are different
across North America, the SDT has been unable to determine a one-size-fits-all definition for local area. Therefore, the SDT adopted an approach that allows
entities to utilize input from stakeholders in an open and transparent process. In this way, any affected party has a mechanism to ensure that the planners are
planning a reliable BES. No change made.
Pat G.
BC Hydro and
3
Negative
Harrington
Power Authority
Gordon
BC Transmission
1
Negative
Rawlings
Corporation
Response: With no comment provided, the SDT is unable to provide a response.
Gregg R
Griffin

City of Green Cove
Springs

3

Affirmative

An objective of the planning process should be to minimize the likelihood and magnitude of
interruption of Demand following Contingency events. However, it is recognized that Demand will

23

Balloter

Company

Segment

Vote

Comment
be interrupted if it is directly served by the Elements removed from service as a result of the
Contingency. Furthermore, in limited circumstances Demand may need to be interrupted to
address BES performance requirements. When interruption of Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management Circumstances where the uses of Demand
interruption are documented, including alternatives evaluated; and where the Demand interruption
is subject to review in an open and transparent stakeholder process that includes addressing
stakeholder comments. Curtailment of firm transfers is allowed, when coupled with the appropriate
re-dispatch of resources obligated to re-dispatch, where it can be demonstrated that Facilities
remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any
firm Demand. Where Facilities external to the Transmission Planner‟s planning region are relied
upon, Facility Ratings in those regions would also be respected.

Response: Thank you for your support.
Guy V. Zito

Northeast Power
Coordinating
Council, Inc.

10

Affirmative

1. There is concern with the use of the term Demand. It is unclear throughout the footnote
whether or not the term Demand includes Interruptible Demand or Demand-Side
Management. It is suggested that interruption of Demand be clarified to not include
Interruptible Demand or Demand-Side Management to more clearly show the permitted
use of Load shedding.
2. It is unclear whether the second bullet includes Demand which is interrupted by the
elements removed from service. Clarification should be made such that Demand which is
interrupted by the elements removed from service should not be included in this bullet.
3. Language that mitigation of Load and/or Demand interruption should be pursued within
the planning process should be reinstated as reinforcement of a Transmission Providers‟
planning obligations to their load customers, and system operations.
4. Footnote „b‟ should be made to read as follows: b) An objective of the planning process is
to minimize the likelihood and magnitude of interruption of Load and/or Demand following
Contingency events. Interruption of Load and/or Demand is discouraged and all measures
to mitigate such interruption should be pursued within the planning process. However, it is
recognized that Load and/or Demand will be interrupted if it is directly served by the
elements automatically removed from service by the Protection System as a result of a
Contingency. Furthermore, in extraordinary circumstances within the planning process
Load and/or Demand may need to be interrupted to address BES performance
requirements. When interruption of Load and/or Demand is utilized within the planning

24

Balloter

Company

Segment

Vote

Comment
process to address BES performance requirements, such interruption is limited to:
• Circumstances where the use of Load and/or Demand interruption are documented,
including alternatives evaluated; and where the Load and/or Demand interruption is made
available for review in an open and transparent stakeholder process. If Load and/or
Demand interruption is necessary, planning should indicate the amount needed, and not
specify how it would be obtained. What Load and/or Demand is interrupted is an
operational decision.
5. Additional comments not included in the material listed for footnote „b‟ on the Comment
Form. In the paragraph below the bullets in footnote „b‟, confusion is introduced through
the use of the term “firm Demand”. It is unclear how this is different than the defined term
“Firm Demand” and what the implications of the term “firm Demand” are. This footnote
should not discourage such adjustments which actually increase the reliability of service to
end users.

6. The last sentence of footnote „b‟ is unnecessary and should be deleted. It is never
acceptable to cause reliability concerns in another area while addressing your own.
Response: 1. The SDT has reorganized the footnote to clarify its intent and address this issue.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
2. The SDT has reorganized the footnote to clarify its intent and address the issue raised.

25

Balloter

Company

Segment

Vote

Comment

3. & 4. The SDT addressed these concerns by including the phrase “including alternatives evaluated” and does not believe that it is appropriate to dictate that
the planners must evaluate “all measures to mitigate” annually or the specific details concerning documentation of alternatives.
5. The SDT has corrected the capitalization errors.
6. Since the planned action of curtailing of firm transfers may adversely impact neighboring systems, the SDT believes that it is important in this situation to
articulate a condition that is normally implied. No change made.
Ajay Garg
Hydro One
1
Affirmative
Hydro One is casting an affirmative vote on the revisions to Table 1, footnote „b‟ in TPL-001-1,
Networks, Inc.
TPL-002-1b, TPL-003-1a, and TPL-004-1. However, we believe the proposed language might be
confusing and should be modified to read as follows: “b) It is recognized that Demand will be
David L
Hydro One
3
Affirmative
interrupted if it is directly served by the Elements removed from service as a result of the
Kiguel
Networks, Inc.
Contingency. When interruption of Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to: o Interruptible Demand or Demand-Side
Management o Circumstances where the uses of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments. Curtailment of
firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to
re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings
and the re-dispatch does not result in the interruption of any firm Demand. Where Facilities
external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those
regions would also be respected.” Note that the voting system does not permit to enter re-lined
comments. We can provide a red-lined document with our proposal upon request.
Response: The SDT believes that the sentences deleted in your proposed footnote are necessary to provide context for the items that follow and has crafted
the language to provide a balance between flexibility and consistency across NERC. The SDT has reorganized the footnote to clarify its intent.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm
Demand is utilized within the planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.

26

Balloter

Company

Segment

Vote

Comment

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be
demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where
Facilities external to the Transmission Planner‟s planning region are relied upon, Facility Ratings in those regions would also be respected.
Henry ErnstDuke Energy
3
Affirmative
The effective date in the Implementation Plan needs to be changed to match the Effective Date in
Jr
Carolina
the standards, in order to clarify the allowed interruption of Non-consequential load before the new
Footnote 'b' takes effect.
Response: The effective dates in the Implementation Plan match those in the standards. No change made.
Mark B
Thompson

Alberta Electric
System Operator

2

Abstain

While the AESO does not generally disagree with the intent of the proposed change, we have
voted "abstain". In particular, as reflected in the adopted Alberta Reliability Standard TPL-002-AB0, no loss of Demand and Generation have been given equal consideration for Category B
contingencies. In addition, within the Alberta energy market structure and the operation of the
transmission system, there are no firm transfers on transmission facilities in Alberta.
Response: Individual jurisdictions are allowed to have more restrictive standards and therefore, this revision to the standard does not dictate that a jurisdiction
must change its requirements. The SDT recognizes that there may be areas or markets that do not utilize terms contained within the standard.

27

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on
the 3rd posting for Project 2010-11: TPL Table 1 Order. These standards were posted for a
45-day public comment period from November 19, 2010 through January 5, 2011. The
stakeholders were asked to provide feedback on the standards through a special Electronic
Comment Form. There were 27 sets of comments, including comments from more than 67
different people from approximately 30 companies representing 8 of the 10 Industry
Segments as shown in the table on the following pages.

http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
The SDT reviewed all of the comments received and has made a clarifying change to the structure of the
footnote to address industry concerns as to the intent of the SDT. No contextual changes have been
made to the footnote. Therefore, the SDT is recommending that this project be moved to a recirculation
ballot.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is:
(1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated;
and where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.

If you feel that your comment has been overlooked, please let us know immediately. Our
goal is to give every comment serious consideration in this process! If you feel there has
been an error or omission, you can contact the Vice President and Director of Standards,
Herb Schrayshuen, at 609-452-8060 or at [email protected]. In addition,
there is a NERC Reliability Standards Appeals Process. 1

1

The appeals process is in the Reliability Standards Development Procedures:
http://www.nerc.com/standards/newstandardsprocess.html.

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Index to Questions, Comments, and Responses
1.

The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply
with a FERC directive which required the ERO to clarify TPL-002-0, Table 1 footnote ‘b’, regarding the planned or controlled interruption of electric supply
where a single contingency occurs on a transmission system. Do you agree
with the proposed changes and if not, please provide specific reasons for your
disagreement.…. .............................................................................................. 7

2

Consideration of Comments on TPL Table 1 Order — Project 2010-11
The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

2

Northeast Power Coordinating Council

Additional Member Additional Organization

Region

3

4

5

6

7

8

9

10

X

Segment
Selection

1.

Al Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Greg Campoli

New York Independent System Operator

NPCC

2

3.

Kurtis Chong

Independent Electricity System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Dean Ellis

Dynegy Generation

NPCC

5

8.

Brian Evans-Mongeon

Utility Services

NPCC

8

9.

Mike Garton

Dominion Resources Services, Inc.

NPCC

5

10.

Brian L. Gooder

Ontario Power Generation Incorporated

NPCC

5

11.

Kathleen Goodman

ISO - New England

NPCC

2

12.

Chantel Haswell

FPL Group, Inc.

NPCC

5

13.

David Kiguel

Hydro One Networks Inc.

NPCC

1

3

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

14.

Michael R. Lombardi

Northeast Utilities

NPCC

1

15.

Randy MacDonald

New Brunswick System Operator

NPCC

2

16.

Bruce Metruck

New York Power Authority

NPCC

6

17.

Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

18.

Robert Pellegrini

The United Illuminating Company

NPCC

1

19.

Si Truc Phan

Hydro-Quebec TransEnergie

NPCC

1

20.

Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC

3

2.

Group

Charles W. Long

SERC Planning Standards Subcommittee

Additional Member Additional Organization

Region

X

Pat Huntley

SERC Reliability Corporation

SERC

10

2.

Bob Jones

Southern Company Services

SERC

1

3.

Darrin Church

Tennessee Valley Authority

SERC

1

4.

Jim Kelley

PowerSouth Energy Cooperative SERC

1

5.

John Sullivan

Ameren Services Company

SERC

1

6.

Phil Kleckley

South Carolina Electric & Gas Co. SERC

1

Group
Additional Member

Carol Gerou

MRO's NERC Standards Review
Subcommittee

Additional Organization

4

5

6

7

8

9

10

X

Segment
Selection

1.

3.

3

X

Region Segment Selection

1. Mahmood Safi

Omaha Public Utility District

MRO

1, 3, 5, 6

2. Chuck Lawrence

American Transmission Company

MRO

1

3. Tom Webb

Wisconsin Public Service Corporation MRO

3, 4, 5, 6

4. Jason Marshall

Midwest ISO Inc.

MRO

2

5. Jodi Jenson

Western Area Power Administration

MRO

1, 6

6. Ken Goldsmith

Alliant Energy

MRO

4

7. Alice Ireland

Xcel Energy

MRO

1, 3, 5, 6

8. Dave Rudolph

Basin Electric Power Cooperative

MRO

1, 3, 5, 6

4

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

9. Eric Ruskamp

Lincoln Electric System

MRO

1, 3, 5, 6

10. Joseph Knight

Great River Energy

MRO

1, 3, 5, 6

11. Joe DePoorter

Madison Gas & Electric

MRO

3, 4, 5, 6

12. Scott Nickels

Rochester Public Utilties

MRO

4

13. Terry Harbour

MidAmerican Energy Company

MRO

1, 3, 5, 6

14. Richard Burt

Minnkota Power Cooperative, Inc.

MRO

1, 3, 5, 6

2

3

4

5

6

4.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

5.

Individual

Sandra Shaffer

PacifiCorp

X

X

X

X

6.

Individual

Andy Tillery

Southern Company

X

X

7.

Individual

Aaron Staley

Orlando Utilities Commission

X

8.

Individual

Greg Rowland

Duke Energy

X

9.

Individual

Si Truc PHAN

Hydro-Quebec TransÉnergie

X

10.

Individual

Tim Ponseti, VP

TVA Trasnmission Plannning & Compliance

X

11.

Individual

Alex Rost

New Brunswick System Operator

12.

Individual

Joe Petaski

Manitoba Hydro

13.

Individual

Bernie Pasternack

Transmission Strategies, LLC

Individual

Michael A. Curtis,
General Counsel

Mohave Electric Cooperative

Individual

David Thorne

Pepco Holding Inc

14.

15.

7

8

9

10

X
X

X

X

X

X

X

X

X

X
X

X
X

X
X

5

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

16.

Individual

John Sullivan

Ameren

X

X

X

X

17.

Individual

Thad Ness

American Electric Power

X

X

X

X

18.

Individual

Bob Casey

Georgia Transmission Corporation

X

19.

Individual

Alice Ireland

Xcel Energy

X

X

X

X

20.

Individual

Saurabh Saksena

National Grid

X

X

21.

Individual

Andrew Z. Pusztai

American Transmission Company

X

22.

Individual

Jason L. Marshall

Midwest ISO

23.

Individual

Michael Lombardi

Northeast Utilities

24.

Individual

Dan Rochester

Independent Electricity System Operator

X

25.

Individual

Gregory Campoli

New York Independent System Operator

X

26.

Individual

Kathleen Goodman

ISO New England Inc

X

27.

Individual

Harold Wyble

Kansas City Power & Light

7

8

9

10

X
X

X

X

X

X

X

X

6

Consideration of Comments on TPL Table 1 Order — Project 2010-11

1. The SDT is proposing a revision to footnote ‘b’ in the TPL tables to comply with a FERC directive which required
the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the planned or controlled interruption of electric
supply where a single contingency occurs on a transmission system. Do you agree with the proposed changes
and if not, please provide specific reasons for your disagreement.

Summary Consideration: The SDT reviewed all of the comments received and has made a clarifying change to the structure of the footnote
to address industry concerns as to the intent of the SDT. No contextual changes have been made to the footnote.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand
following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is
recognized [llh1]that Firm Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a result of the
Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may
need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the planning process
to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the
Demand interruption is subject to review in an open and transparent stakeholder process that includes addressing stakeholder
comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can
be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm
Demand. Where Facilities external to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would
also be respected.

Organization
SERC Planning Standards
Subcommittee

Yes or No
No

Question 1 Comment
The PSS agrees that the proposed language for footnote b provides some additional clarity. While we
generally support the concept, we have concerns that the phrase “is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments” remains ambiguous and
should be clarified by limiting stakeholder input to those who have load at risk or local regulators obligated to

7

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
act on their behalf.
Revise the first sentence of the last paragraph to read: “To prepare for a second contingency, curtailment of
firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch,
where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand.”The comments expressed herein represent a consensus of the
views of the above-named members of the SERC EC Planning Standards Subcommittee only and should not
be construed as the position of SERC Reliability Corporation, its board, or its officers.

Response: The stakeholder process needs to be open and transparent but it is up to the entity to establish the process and whom it may include. No change
made.
As drafted, footnote ‘b’ clarifies that re-dispatch is allowable to “remain within” ratings, not to bring the Facilities within ratings. The draft language recognizes that
System adjustments may be required after a single Contingency, since entities may utilize ratings in the planning horizon that can only be utilized for a limited
time, such as a 2 hour emergency rating. It further clarifies that if an entity is obligated to re-dispatch its generation resources, the Transmission Planner can plan
to re-dispatch those resources for a single Contingency. However, if the resources that impact the affected Facilities are not obligated to re-dispatch, the firm
transfers cannot be curtailed. Therefore, the SDT does not believe that it is necessary to add the words “To prepare for the next Contingency” to the footnote. No
change made.
Xcel Energy

No

As this is currently drafted, planners would be required to host a forum with stakeholders to discuss
hypothetical actions that may be taken in an emergency. We do not see the value in this, nor is it clear who
would be considered stakeholders that should attend this forum. For example, we assume it would be the
transmission owner’s meeting with distribution providers to discuss the possibility of load shedding. Would
that be adequate? Xcel Energy is both a Transmission Planner and a Distribution Provider. In this case
would the stakeholder be the end user? This should be struck or more clearly defined.

Response: The stakeholder process needs to be open and transparent but it is up to the entity to establish the process and whom it may include. No change
made.
New York Independent System
Operator

No

1. Proposed revised footnote language:b) It is recognized that Demand will be interrupted if it is directly
served by the Elements removed from service as a result of the Contingency. When interruption of
Demand is utilized within the planning process to address BES performance requirements, such
interruption is limited to: o Interruptible Demand or Demand-Side Management o Circumstances where
the uses of firm Demand interruption not directly interrupted by the contingency are documented,
including alternatives evaluated; and where the firm Demand interruption is subject to review in an open
and transparent stakeholder process. Curtailment of firm transfers is allowed, when coupled with the
appropriate re-dispatch of resources obligated to re-dispatch where it can be demonstrated that Facilities

8

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
remain within applicable Facility Ratings and the re-dispatch does not result in the interruption of any firm
Demand.
2. Comments:There are generic concerns with the footnote as amended that must be addressed. The first
is the use of the term “Demand”. It is very unclear throughout the footnote whether or not the term
Demand includes Interruptible Demand or Demand-Side Management. It is suggested that interruption of
Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly
show the permitted use of that option for load shedding.
3. Further confusion is introduced through the use of the term “firm Demand” in some locations. It is unclear
how this is different than the defined term “Firm Demand” and what the implications of the term “firm
Demand” are.
4. The first and third sentences of the first paragraph are unnecessary and should be deleted. However, if
they are to be retained, the first sentence is unacceptable in its current state. In some instances,
Interruptible Demand or Demand-Side Management are utilized in lieu of transmission additions. These
can be considered as acceptable mitigation and there is no justification to minimize their use. Therefore
some clarification to the term Demand in the first sentence must be made.
5. It is unclear whether the second bullet includes Demand which is interrupted by the elements removed
from service. Clarification should be made such that Demand which is interrupted by the elements
removed from service should not be included in this bullet.
6. The second portion of the second bullet should be deleted as it is unncessary: “and where the Demand
interruption is subject to review in an open and transparent stakeholder process that includes addressing
stakeholder comments.” If this is to be retained, the very last portion should be deleted “that includes
addressing stakeholder comments”. The term “addressing” is unclear. This can be misconstrued to infer
that plans must be changed in response to stakeholder comments. This may be inappropriate and may
be impossible if conflicting comments are received. It may also create a new standard that all comments
must be “addressed”, which may not be a part of the stakeholder process across NERC’s footprint.
7. The first sentence of the paragraph under the two bullets seems to prevent a situation where a
combination of re-dispatch and the interruption of Demand are utilized. This restriction could prevent a
situation where the use of re-dispatch decreases the amount of Demand which must be interrupted. This
footnote should not discourage such adjustments which actually increase the reliability of service to end
users.
8. This same sentence also uses the term “shedding of firm Demand”. This should be replaced with
“Demand interruption” such that it is consistent with the second bullet; otherwise an unnecessary new
term has been introduced.

9

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
9. The last sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause
reliability concerns in another area while addressing your own. This same thought would have to be
added to multiple NERC standards if it was added here, otherwise it would infer that such actions are
acceptable in all other standards.

Response: 1. See response to National Grid #1 in ballot comment responses.
2. See response to National Grid #1 in ballot comment responses.
3. See response to National Grid #6 in ballot comment responses.
4. The SDT has reorganized the footnote to clarify its intent and address the issues raised.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result [llh2]in the shedding of any firm Demand. Where Facilities external
to the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
5. See response to National Grid #2 in ballot comment responses.
6. See response to National Grid #4 in ballot comment responses.
7. The SDT has reorganized the footnote to clarify its intent and address the issues raised.
8. The SDT has reorganized the footnote to clarify its intent and address the issues raised.

10

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

9. See response to National Grid #7 in ballot comment responses.
ISO New England Inc

No

1. The following comments are provided in regard to this proposal. The first and third sentences of the first
paragraph are unnecessary. While we agree with the concept, it is unclear as to how inclusion of these
sentences in a standard creates a measureable requirement.
2. There are generic concerns with the footnote as currently proposed. The first is the use of the term
“Demand.” It is unclear whether the term Demand includes Interruptible Demand and Demand-Side
Management. It is suggested that interruption of Demand be clarified to exclude Interruptible Demand
and Demand-Side Management to more clearly show the permitted use of those options.
3. The second concern is that it is unclear whether the second bullet includes Demand which is interrupted
by the elements removed from service. Clarification should be made such that Demand which is
interrupted by the elements removed from service should not be included in this bullet.
4. The third is that not all areas have stakeholder processes. Documenting the use of Demand Interruption
should be sufficient without requiring stakeholder review. Therefore the second portion of the second
bullet “including alternatives evaluated; and where the Demand interruption is subject to review in an
open and transparent stakeholder process that includes addressing stakeholder comments” is
unnecessary and should be deleted. “Addressing stakeholder comments” introduces undefined actions
which may be required in response to the comments. For those areas that already have stakeholder
processes, stakeholder comments are by definition addressed. As a result, at a minimum “that includes
addressing stakeholder comments” should be deleted. Furthermore, for areas that do not have
stakeholder processes, so long as they publish their studies impacted parties are aware of the role of
demand response.
5. The fourth is that the second paragraph seems to be restricting the use of Demand interruption for the
sake of Firm Transfer reduction. This can be stated directly without adding the confusion of re-dispatch.
By coupling re-dispatch with a constraint of not shedding Demand, the paragraph also creates confusion
as to what to do in a situation where the amount of Demand that is allowed to be shed in the first
paragraph could be reduced with re-dispatch. Would re-dispatch not be allowed? We suggest that the
paragraph be rewritten as follows: “Curtailment of firm transfers is allowed to meet BES performance
requirements and meet applicable Facility Ratings, where it can be demonstrated it does not result in the
interruption of any Demand (other than Interruptible Demand or Demand Side Management).”
6. The fifth is if the term ‘firm demand’ survives the proposed changes; is there an intended distinction
between the use of the term “firm Demand” and the defined term “Firm Demand”? If these terms are
intended to be differently, it is unclear what the term “firm Demand” represents.
7. The final comment is that the last sentence of footnote B is unnecessary and should be deleted. It is

11

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
never acceptable to cause reliability concerns in another area while addressing your own. This same
thought would have to be added to multiple NERC standards if it was added here, otherwise it would infer
that such actions are acceptable in all other standards.
8. If the first and third sentences must be retained the following wording for the footnote is proposed:b) An
objective of the planning process should be to minimize the likelihood and magnitude of interruption of
Demand, (excluding Interruptible Demand or Demand-Side Management), following Contingency events.
However, it is recognized that Demand will be interrupted if it is directly served by the Elements removed
from service as a result of the Contingency. Furthermore, in limited circumstances Demand may need to
be interrupted to address BES performance requirements. When interruption of Demand is utilized within
the planning process to address BES performance requirements, such interruption is limited to: o
Interruptible Demand or Demand-Side Management o Circumstances where the uses of Demand
interruption not directly interrupted by the contingency are documented. Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can be
demonstrated it does not result in the interruption of any Demand (other than Interruptible Demand or
Demand Side Management).

Response: 1. The SDT believes that the first part of the footnote is necessary to provide context for the items that follow and has crafted the language to
provide a balance between flexibility and consistency across NERC. No change made.
2. See ballot response to NPCC #1.
3. See ballot response to NPCC #2.
4. The SDT believes that in situations where an entity’s planning studies require the interruption of firm load to remain within BES Facility ratings that the entity
needs to share those plans in an open and transparent stakeholder process to ensure that other parties that may be adversely impacted by those decisions have
the ability to review and comment on those plans. No change made.
5. See ballot response to NPCC #5.
6. The SDT has corrected the indicated errors.
7. See ballot response to NPCC #6.
8. The SDT has reorganized the text in the footnote to address this concern.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited

12

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
Northeast Power Coordinating
Council

No

There is concern with the use of the term Demand. It is unclear throughout the footnote whether or not the
term Demand includes Interruptible Demand or Demand-Side Management. It is suggested that interruption
of Demand be clarified to not include Interruptible Demand or Demand-Side Management to more clearly
show the permitted use of Load shedding.
It is unclear whether the second bullet includes Demand which is interrupted by the elements removed from
service. Clarification should be made such that Demand which is interrupted by the elements removed from
service should not be included in this bullet.
Language that mitigation of Load and/or Demand interruption should be pursued within the planning process
should be reinstated as reinforcement of a Transmission Providers’ planning obligations to their load
customers, and system operations.
Footnote ‘b’ should be made to read as follows:b) An objective of the planning process is to minimize the
likelihood and magnitude of interruption of Load and/or Demand following Contingency events. Interruption of
Load and/or Demand is discouraged and all measures to mitigate such interruption should be pursued within
the planning process. However, it is recognized that Load and/or Demand will be interrupted if it is directly
served by the elements automatically removed from service by the Protection System as a result of a
Contingency. Furthermore, in extraordinary circumstances within the planning process Load and/or Demand
may need to be interrupted to address BES performance requirements. When interruption of Load and/or
Demand is utilized within the planning process to address BES performance requirements, such interruption
is limited to: o Circumstances where the use of Load and/or Demand interruption are documented,
including alternatives evaluated; and where the Load and/or Demand interruption is made available for review
in an open and transparent stakeholder process.If Load and/or Demand interruption is necessary, planning
should indicate the amount needed, and not specify how it would be obtained. What Load and/or Demand is

13

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
interrupted is an operational decision.
Additional comments not included in the material listed for footnote ‘b’ on the Comment Form. In the
paragraph below the bullets in footnote ‘b’, confusion is introduced through the use of the term “firm Demand”.
It is unclear how this is different than the defined term “Firm Demand” and what the implications of the term
“firm Demand” are. This footnote should not discourage such adjustments which actually increase the
reliability of service to end users. The last sentence of footnote ‘b’ is unnecessary and should be deleted. It
is never acceptable to cause reliability concerns in another area while addressing your own.

Response: This comment is identical to the one made by NPCC in the ballot and the SDT has answered the comment in that forum.
Arizona Public Service Company

No

It is not clear whether both bullets under "footnote b" have to be met or only one of the two have to be met. It
is suggested that the standard be very clear about this.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Southern Company

No

Southern Company is voting "no" on the footnote b ballot because of concerns that the reliability of firm
transfers could be compromised. The existing Table I Transmission System Standards, which have been in
place as early as the 1997 NERC Planning Standards, do not allow Loss of Demand or Curtailed Firm
Transfers under single (Category B) contingencies. Footnote B addressed two areas: 1) the loss of radial or
local network load, which Southern Company agrees that the drafting team has appropriately clarified and 2)
preparing for the next contingency, which Southern Company does not agree has been appropriately
clarified.Southern Company believes the proposed wording "Curtailment of firm transfers is allowed, when
coupled with the appropriate re-dispatch of resources obligated to re-dispatch" now allows for the curtailment
of firm transfers for single contingencies, whereas Southern Company did not believe this was previously
permitted under the standards. Southern Company interprets the new language to allow a planner to curtail
firm transfers (generation) to address a single contingency. Southern Company interpreted the original
language to not permit the curtailment of firm transfers (generation) for a single contingency, but rather that a
planner would develop a suitable transmission reinforcement or other mitigation. Southern Company is
concerned that the proposed language could result in a degradation in the dependability of firm transfers
impacting the reliability of those customers who rely upon them. Southern Company agrees that a system
reconfiguration including the redispatch of generation is appropriate when preparing for a second contingency
(Category C).Therfore, a distinction is needed between what is allowed in response to a first contingency and
what is allowed to be prepared for a second contingency. The curtailment of firm transfers should not be
allowed as a response to the first contingency. This practice would undermine the concept of firm transfers.
The curtailment of firm transfers should only be allowed in footnote b as a system adjustment to be prepared
for a second contingency. We propose the following to clarify that curtailments are permitted only to prepare

14

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
for the second contingency. "To prepare for the next contingency, curtailment of firm transfers is allowed,
when coupled with the appropriate re-dispatch of resources obligated to re-dispatch".

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Orlando Utilities Commission

No

The current language provides a balance between the end goal of reliablity (no load loss for B events) and the
practical constraint that project cost may outweigh the benefit. Two things are unclear though. Item one: The
standard team should clarify if the bullets under note B are intended to be an AND (both conditions met) or an
OR (either condition met). As currently written it is not clear.
Item #2: The section under firm transfers is in conflict with the section above. If Demand is being curtailed
under the first or second bullet and it’s served by firm service then service should also be curtailed, however
as written any demand served by firm service could not be curtailed.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Duke Energy

Yes

The effective date in the Implementation Plan needs to be changed to match the Effective Date in the
standards, in order to clarify the allowed interruption of Non-consequential load before the new Footnote ‘b’
takes effect.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Hydro-Quebec Transenergie

Yes

Paragraph should be more clear as:b) An objective of the planning process should be to minimize the
likelihood and magnitude of interruption of Demand following Contingency events. However, it is recognized
that Demand will be interrupted if it is directly served by the Elements removed from service as a result of the
Contingency. Furthermore, in limited circumstances within the planning process, Demand may need to be
interrupted to address BES performance requirements. In such case : o Only Interruptible Demand or
Demand-Side Management are allowed;o Circumstances where the uses of Demand interruption is needed
shall be documented, compared to alternatives, and reviewed in an open and transparent stakeholder
process that address stakeholder comments. Curtailment of firm transfers is allowed, when coupled with the
appropriate and necessary re-dispatch of resources where it can be demonstrated that this does not result in
the shedding of any firm Demand and that Facilities remain within applicable Facility Ratings, including
Facilities external to the Transmission Planner’s planning region when they are relied upon.

Response: The SDT believes that the changes indicated in your proposed footnote do not add any additional clarity. However, the SDT has reorganized the
footnote to clarify its intent.

15

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is: (1) directly served by the
Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When interruption of Firm Demand is utilized within the
planning process to address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated; and where the Demand interruption is
subject to review in an open and transparent stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to re-dispatch, where it can be demonstrated
that Facilities remain within applicable Facility Ratings and the re-dispatch does not result in the shedding of any firm Demand. Where Facilities external to
the Transmission Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
TVA Trasnmission Plannning &
Compliance

No

TVA appreciates the SDT’s efforts to clarify and improve this complex and challenging area. However, as
mentioned in our last comments regarding footnote b, TVA still believes that the SDT’s proposal is still
focusing more on reliability of local loads than on the overall reliability of the BES. Reliability of local loads
should be addressed outside the TPL standards and therefore should not be used/referenced in footnote b.
Existing stakeholder processes (referred to in the SDT proposal) typically focus on larger system issues and
not on local load serving. TVA believes that some local load should be allowed to be dropped in order to
maintain BES reliability. Instead of the proposed footnote b, TVA suggests that the SDT define a “local area”
with guidelines detailing the reliability requirements for these local area loads. This would separate the local
area load requirements from the BES requirements in the TPL standards.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
New Brunswick System Operator

No

NBSO agrees with the principles of the current version of the proposed footnote, as far as NBSO’s
interpretation of the footnote is correct. NBSO has the following detailed comments:1. The first paragraph
contains many general statements that attempts to capture essential planning principles. NBSO feels that
such language is not suited for a footnote. NBSO suggests re-wording of the first paragraph to
state:Interruption of Demand may be utilized within the planning process to address BES performance
requirements. Such cases are limited to:NBSO also suggests turning the phrase that addresses Demand lost
that was served by elements removed from service as a result of a Contingency into a bullet item. NBSO feels

16

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
that this adds clarity since all of the acceptable instances of Demand interruption are now listed as bulleted
items.2. NBSO interprets that the currently proposed footnote allows for the two bulleted options to be used
exclusively or in combination. Thus for clarification NBSO suggests adding “or” after each bulleted item, with
the exclusion of the final bulleted item.3. NBSO suggests removing the last sentence of the last paragraph.
Likely all industry members understand that causing reliability concerns in other areas is never acceptable.
This principle is not limited to the standard in question, and thus such a statement could require the update of
other standards.4. NBSO interprets that the use of the word “Demand” in the second bullet of the proposed
footnote is referring to use of Firm Demand since the first bullet covers the other types of Demand (Demand =
Firm Demand + Interruptible Demand). As such NBSO suggests replacing “Demand” with “Firm Demand” in
the second bullet.5. NBSO feels that the statement “that includes addressing stakeholder comments” should
be removed from the last phrase of the second bullet. An open and transparent stakeholder process should
adequately address stakeholder comments and concerns. Explicitly specifying that all stakeholder comments
be addressed may add undue burden if the word “address” is misconstrued. The task of addressing
stakeholder comments is more appropriately addressed and defined in each area’s respective process.6.
NBSO suggests replacing the word “shedding” with “interruption” in the last phrase of the last paragraph to
remain consistent with the rest of the proposed footnote. NBSO also suggests capitalizing “firm” in the term
“Firm Demand” to remain consistent with the NERC glossary of terms.7. There is no term “transfers” in the
NERC glossary of terms. Perhaps some other defined term from the glossary could be used in lieu of
“transfers” (e.g. Firm Transmission Service).Taking into account the NBSO comments, the footnote could
read as follows:b) Interruption of Demand may be utilized within the planning process to address BES
performance requirements. Such cases are limited to:-Demand directly served by Elements removed from
service as a result of a Contingency, or-Use of Interruptible Demand or Demand-Side Management, orInterruption of Firm Demand when acceptable circumstances for such interruptions are documented
(including alternatives evaluated), and where the Firm Demand interruption is subject to review in an open
and transparent stakeholder process.Curtailment of Firm Transmission Service is allowed when coupled with
the appropriate re-dispatch of resources obligated to do so, and it can be demonstrated that Facilities remain
within applicable Facility Ratings and there is no additional interruption of Firm Demand.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Manitoba Hydro

No

The last bullet should be made clearer by adding the words “in jurisdictions” before the word “where”. Not all
jurisdictions are mandated to have a stakeholder process, so the standard should be clearly written to
recognize this situation. "Circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and IN JURISDICTIONS where the Demand interruption is subject to review in an
open and transparent stakeholder process that includes addressing stakeholder comments."

17

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Ameren

No

We agree with the statement that an objective of the planning process should be to minimize the likelihood
and magnitude of interruption of Demand following single contingency events. While we appreciate the
drafting team’s efforts in removing the need for acceptance by other parties in the stakeholder process, we
still feel that language in the second bullet of the revised footnote b should be modified to remove all
references to an open and transparent stakeholder process. Existing RTO stakeholder processes that we are
aware of focus on larger system issues, rather than on local load serving issues. Therefore, we believe that
the load serving issues following single contingency events are issues between the customer and the utility,
and should be addressed in one-on-one forums between those entities.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
National Grid

No

National Grid supports the direction the drafting team has taken. However, it has a few concerns with the
language of the footnote as amended. 1. Use of the term “Demand”: In the first sentence, it is unclear
whether the term Demand includes Interruptible Demand and Demand-Side Management. It is suggested
that interruption of Demand be clarified to exclude Interruptible Demand or Demand-Side Management. 2. It
is unclear whether the second bullet includes Demand which is interrupted by the elements removed from
service. Clarification should be made such that Demand which is interrupted by the elements removed from
service should not be included in this bullet. 3. National Grid also suggests changing “Demand interruption” to
“interruption of Demand” in second bullet under “b)” to avoid awkward and incorrect phasing.4. ‘Addressing
stakeholder comments’ introduces undefined actions which may be required in response to the comments. If
‘Demand interruption is subject to review in an open and transparent stakeholder process’, then stakeholder
comments will be addressed without creating an undefined commitment to require it. As a result, “that
includes addressing stakeholder comments” should be deleted. 5. The second paragraph seems to be
restricting the use of Demand interruption for the sake of Firm Transfer reduction. This can be stated directly
without adding the confusion of re-dispatch. By coupling re-dispatch with a constraint of not shedding
Demand, the paragraph also creates confusion as to what to do in a situation where the amount of Demand
that is allowed to be shed in the first paragraph could be reduced with re-dispatch. Would re-dispatch not be
allowed? National Grid suggests that the paragraph be rewritten as follows: ‘Curtailment of firm transfers is
allowed to meet BES performance requirements and meet applicable Facility Ratings, where it can be
demonstrated it does not result in the interruption of any Demand (other than Interruptible Demand or
Demand Side Management).’ 6. National Grid seeks clarification if there is an intended distinction between
the use of the term “firm Demand” and the defined term “Firm Demand” or is that just a typo?7. The last
sentence of footnote B is unnecessary and should be deleted. It is never acceptable to cause reliability
concerns in another area while addressing your own. This same thought would have to be added to multiple

18

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Question 1 Comment
NERC standards if it were added here, otherwise it would infer that such actions are acceptable in all other
standards.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Northeast Utilities

No

The revised language of Footnote b suggests that non-consequential demand interruption (load that is not
directly served by the elements removed from service as a result of the contingency) could be used to
mitigate reliability concerns arising from NERC Category B contingency events (i.e., single element
contingencies). This language seems to encourage operational workarounds and adds burdens for operators
of the system. NU believes this is not consistent with planning a highly reliable bulk electric system and thus
does not support this weaker language.

Response: This comment is identical to one made in the ballot and the SDT has answered the comment in that forum.
Kansas City Power & Light

Yes

MRO's NERC Standards Review
Subcommittee

Yes

PacifiCorp

Yes

Transmission Strategies, LLC

Yes

Mohave Electric Cooperative

Yes

Pepco Holding Inc

Yes

American Electric Power

Yes

Georgia Transmission
Corporation

Yes

American Transmission
Company

Yes

appreciates the efforts of the SDT and supports revision of TLP-002-0 Table 1 footnote “b” as stated in this
draft.

19

Consideration of Comments on TPL Table 1 Order — Project 2010-11

Organization

Yes or No

Midwest ISO

Yes

Independent Electricity System
Operator

Yes

Question 1 Comment

Response: Thank you for your support.

20

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards

Standards

Functions That Must Comply
With the Associated
Requirements
Transmission
Planning
Planner
Authority

TPL-001-0.2: System Performance Under Normal (No
Contingency) Conditions (Category A)

X

X

TPL-002-0c: System Performance Following Loss of a Single
Bulk Electric System Element (Category B)
TPL-003-0b: System Performance Following Loss of Two or
More Bulk Electric System Elements (Category C)
TPL-004-0a: System Performance Following Extreme Events
Resulting in the Loss of Two or More Bulk Electric System
Elements (Category D)

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The effective date for footnote ‘b’ will be the first day of the first calendar quarter, 60 months
after applicable regulatory approval. In those jurisdictions where no regulatory approval is
required, the effective date will be the first day of the first calendar quarter, 60 months after
Board of Trustees adoption.
All other requirements remain in effect as per previous approvals.

116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns

D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

System Limits or Impacts

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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S ta n d a rd TP L-001-1 — S ys te m P e rfo rm a n c e Un d e r No rm a l Co n d itio ns
D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that
Firm Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a result of
the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When
interruption of Firm Demand is utilized within the planning process to address BES performance requirements,
such interruption is limited to circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is
due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5.

Standards re-posted in September 2010.

4.6.Re-ballotted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

1. 4. Recirculation ballot

January 2011

2. 5. Submit to BOT for approval

January 2011

3. 6. File with FERC

February 2011

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A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

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R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-1_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-1_R1 and TPL-001-1_
R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-1_R3.
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D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009

Revised

1

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Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Dra ft 25: Au g u s t 30, 2010J a n u a ry 26, 2011

System Limits or Impacts

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Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System
Stable and
both Thermal
and Voltage
Limits within
Applicable
Rating a

Loss of
Demand or
Curtailed Firm
Transfers

Cascading
Outages

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section

Yes

2. Breaker (failure or internal Fault)

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e
Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

D

d

Extreme event resulting in
two or more (multiple)

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

Dra ft 25: Au g u s t 30, 2010J a n u a ry 26, 2011

3. Transformer

Evaluate for risks and
consequences.


May involve substantial loss of
customer Demand and

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elements removed or
Cascading out of service.

2. Transmission Circuit

4. Bus Section

e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is
recognized that Firm Demand will be interrupted if it is: (1) directly served by the Elements removed from
service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load.
Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES performance
requirements. When interruption of Firm Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated
to re-dispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the redispatch does not result in the shedding of any firm Demand. Where Facilities external to the Transmission
Planner’s planning region are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is

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due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.
Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

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A. Introduction
1.

Title: System Performance Under Normal (No Contingency) Conditions (Category A)

2.

Number: TPL-001-0.1

3.

Purpose: System simulations and associated assessments are needed periodically to
ensure that reliable systems are developed that meet specified performance
requirements with sufficient lead time, and continue to be modified or upgraded as
necessary to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date:

May 13, 2009

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect
on the first day of the first calendar quarter, 60 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, the effective
date will be the first day of the first calendar quarter, 60 months after Board of Trustees
adoption. All other requirements remain in effect per previous approvals. The existing
Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1. The Planning Authority and Transmission Planner shall each demonstrate through a
valid assessment that its portion of the interconnected transmission system is planned
such that, with all transmission facilities in service and with normal (pre-contingency)
operating procedures in effect, the Network can be operated to supply projected
customer demands and projected Firm (non- recallable reserved) Transmission
Services at all Demand levels over the range of forecast system demands, under the
conditions defined in Category A of Table I. To be considered valid, the Planning
Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance
following Category A of Table 1 (no contingencies). The specific elements
selected (from each of the following categories) shall be acceptable to the
associated Regional Reliability Organization(s).
R1.3.1. Cover critical system conditions and study years as deemed
appropriate by the entity performing the study.
R1.3.2. Be conducted annually unless changes to system conditions do not
warrant such analyses.

Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

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R1.3.3. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time
solutions.
R1.3.4. Have established normal (pre-contingency) operating procedures in
place.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed for selected demand levels over the range of forecast
system demands.
R1.3.7. Demonstrate that system performance meets Table 1 for Category A
(no contingencies).
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive
resources are available to meet system performance.
R1.4.

Address any planned upgrades needed to meet the performance requirements
of Category A.

R2. When system simulations indicate an inability of the systems to respond as prescribed
in Reliability Standard TPL-001-01_R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system
performance as described above throughout the planning horizon.
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of
facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

Review, in subsequent annual assessments, (where sufficient lead time exists),
the continuing need for identified system facilities. Detailed implementation
plans are not needed.

R3. The Planning Authority and Transmission Planner shall each document the results of
these reliability assessments and corrective plans and shall annually provide these to its
respective NERC Regional Reliability Organization(s), as required by the Regional
Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-001-01_R1 and TPL-0010_1_ R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its Reliability Assessments and corrective plans per
Reliability Standard TPL-001-01_R3.
Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

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D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.

1.2. Compliance Monitoring Period and Reset Time Frame
Annually

1.3. Data Retention
None specified.

1.4. Additional Compliance Information
2.

Levels of Non-Compliance
2.1. Level 1: Not applicable.
2.2. Level 2: A valid assessment and corrective plan for the longer-term planning
horizon is not available.
2.3. Level 3: Not applicable.
2.4. Level 4: A valid assessment and corrective plan for the near-term planning
horizon is not available.

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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

Ad o pte d b y NERC Boa rd of Trus te e s : Oc tobe r 29, 2008
Effe c tive Da te : Ma y 13, 2009

Change Tracking

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Table I. Transmission System Standards – Normal and Emergency Conditions
ContingenciesTBD
Category1

System Limits or ImpactsRevised footnote ‘b’
pursuant to FERC Order RM06-16-009

Split Cells

Revised

Formatted Table
Inserted Cells

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Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System
Stable and
Loss of
both Thermal
Demand or
and Voltage
Cascading
Outages
Limits within Curtailed Firm
Transfers
Applicable
a
Rating

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø)
Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting
in the loss of two
or more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing ,
Manual System Adjustments, followed by
another SLG or 3Ø Fault, with Normal
e

Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system
adjustments, followed by another
Category B (B1, B2, B3, or B4)
contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck
breaker or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service.

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus
transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully
redundant Special Protection System (or Remedial Action
Scheme) in response to an event or abnormal system
condition for which it was not intended to operate
14. Impact of severe power swings or oscillations from
Disturbances in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit
as determined and consistently applied by the system or facility owner. Applicable Ratings may include
Emergency Ratings applicable for short durations as required to permit operating steps necessary to maintain
system control. All Ratings must be established consistent with applicable NERC Reliability Standards
addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems. To prepare for the next
contingency, system adjustments are permitted, including curtailments of contracted Firm (non-recallable
reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that
Firm Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a result of
the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. Furthermore, in limited
circumstances Firm Demand may need to be interrupted to address BES performance requirements. When
interruption of Firm Demand is utilized within the planning process to address BES performance requirements,
such interruption is limited to circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to
customers (load shedding), the planned removal from service of certain generators, and/or the curtailment of
contracted Firm (non-recallable reserved) electric power Transfers may be necessary to maintain the overall
reliability of the interconnected transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the
transmission planning entity(ies) will be selected for evaluation. It is not expected that all possible facility
outages under each listed contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault is

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due to failure of any protection system component such as a relay, circuit breaker, or current transformer, and
not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g.,
station entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Draft 5: January 26, 2011

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Draft 5: January 26, 2011

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Draft 5: January 26, 2011

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.

Draft 5: January 26, 2011

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D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Draft 5: January 26, 2011

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Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to circumstances where the use of Demand
interruption are documented, including alternatives evaluated; and where the Demand interruption is subject to review
in an open and transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
4.6.Re-ballotted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

41. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is:
(1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives
evaluated; and where the Demand interruption is subject to review in an open and transparent
stakeholder process that includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.

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f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.
Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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S ta n d a rd TP L-002-0b 1b — S ys te m P e rform a nc e Fo llowin g Lo s s o f a S in g le BES Ele m e nt
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-0b1b

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: Immediately after approval of applicable regulatory authorities.

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-01_R1 and TPL-002-01_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-01_R3.

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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S ta n d a rd TP L-002-0b 1b — S ys te m P e rform a nc e Fo llowin g Lo s s o f a S in g le BES Ele m e nt
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

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S ta n d a rd TP L-002-0b 1b — S ys te m P e rform a nc e Fo llowin g Lo s s o f a S in g le BES Ele m e nt
Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: NovemberDraft 5, 2009: January 26, 2011
Effective Date: TBD

Page 7 of 13

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

Evaluate for risks and
consequences.

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator



3. Transformer

2. Transmission Circuit

4. Bus Section
e



3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)



6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)

May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to circumstances where the use of Demand
interruption are documented, including alternatives evaluated; and where the Demand interruption is subject to review
in an open and transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-002-0a 1b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Adopted by NERC Board of Trustees: February 8, 2005
Effective Date: TBD

Page Draft 5: January 26, 2011

S ta n d a rd TP L-003-1a — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f Two o r Mo re BES Ele m e n ts

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1.

SAR submitted to SC in April 2010.

2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Draft 5: January 26, 2011

Page 1 of 11

S ta n d a rd TP L-003-1a — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f Two o r Mo re BES Ele m e n ts

In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

Draft 5: January 26, 2011

Page 2 of 11

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Draft 5: January 26, 2011

Page 3 of 11

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES
performance requirements. When interruption of Firm Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to circumstances where the use of Demand interruption are
documented, including alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1.

SAR submitted to SC in April 2010.

2. SAR approved by SC in April 2010.
3.

30-day pre-ballot period completed in May 2010.

4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
4.6.Re-ballotted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

1.4. Recirculation ballot

January 2011

2.5. Submit to BOT for approval

January 2011

3.6. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-1_R1 and TPL-003-1_R2.

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-1_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

1a

TBD

Revised footnote ‘b’ pursuant to FERC Order
RM06-16-009.

Revised

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Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading c
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is:
(1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements,, such interruption is limited to:

o

Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated;
and where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.

Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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A. Introduction
1.

Title:
System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

2.

Number:

3.

Purpose:
System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements, with
sufficient lead time and continue to be modified or upgraded as necessary to meet present and
future System needs.

4.

Applicability:

TPL-003-0a1a

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

April 23, 2010

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission systems is planned such that the
network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand Levels over the range of forecast
system demands, under the contingency conditions as defined in Category C of Table I
(attached). The controlled interruption of customer Demand, the planned removal of
generators, or the Curtailment of firm (non-recallable reserved) power transfers may be
necessary to meet this standard. To be valid, the Planning Authority and Transmission Planner
assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category C of Table 1 (multiple contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category C contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system demands.
R1.3.7. Demonstrate that System performance meets Table 1 for Category C
contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet System performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
Demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category C.

R1.5.

Consider all contingencies applicable to Category C.

When system simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-003-01_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of these
Reliability Assessments and corrective plans and shall annually provide these to its respective
NERC Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-003-01_R1 and TPL-003-01_R2.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-003-01_R3.
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2:
A valid assessment and corrective plan for the longer-term planning horizon
is not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
A valid assessment and corrective plan for the near-term planning horizon is
not available.
E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0

April 1, 2005

Add parenthesis to item “e” on page 8.

Errata

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

April 23,
2010TBD

FERC approval of interpretation of TPL003-0 R1.3.12Revised footnote ‘b’ pursuant to

InterpretationRevised

0a1a

FERC Order RM06-16-009.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

Page Draft 5: January 26, 2011

Formatted Table

S ta n d a rd TP L-003-0a1a — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f Two o r Mo re BES Ele m e n ts

Ta b le I. Tra n s m is s io n S ys te m S ta n d a rd s – No rm a l a n d Em e rg e n c y Co n d itio n s
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Cascading c
Voltage
Outages
Curtailed Firm
Limits within
Transfers
Applicable
a
Rating

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e

3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e

Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES
performance requirements. When interruption of Firm Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to circumstances where the use of Demand interruption are
documented, including alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.
Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and TPL-003-0
Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12 Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Adopted by NERC Board of Trustees: July 30, 2008
Effective Date: April 23, 2010

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

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R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

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Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

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Table I. Transmission System Standards – Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES
performance requirements. When interruption of Firm Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to circumstances where the use of Demand interruption are
documented, including alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
4.6.Re-ballotted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

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In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.

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In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. 30-day posting

September 2010

2. 30-day pre-ballot period

November 2010

3. Initial ballot

December 2010

41. Recirculation ballot

January 2011

52. Submit to BOT for approval

January 2011

63. File with FERC

February 2011

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A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-1

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.
R1.3.5. Include existing and planned facilities.

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R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-1_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-1_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences
1.

None identified.

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Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

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Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

e

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. However, iIt is recognized that Firm Demand will be interrupted if it is:
(1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
address BES performance requirements. When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to:
Interruptible Demand or Demand-Side Management
Ccircumstances where the use of Demand interruption are documented, including alternatives evaluated;
and where the Demand interruption is subject to review in an open and transparent stakeholder process that
includes addressing stakeholder comments.
Curtailment of firm transfers is allowed, when coupled with the appropriate re-dispatch of resources obligated to redispatch, where it can be demonstrated that Facilities remain within applicable Facility Ratings and the re-dispatch does
not result in the shedding of any firm Demand. Where Facilities external to the Transmission Planner’s planning region
are relied upon, Facility Ratings in those regions would also be respected.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.

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e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR submitted to SC in April 2010.
2. SAR approved by SC in April 2010.
3. 30-day pre-ballot period completed in May 2010.
4. Initial ballot completed in May 2010.
5. Standards re-posted in September 2010.
6. Re-balloted in December 2010.
Proposed Action Plan and Description of Current Draft:
The SAR for this project proposed changes to TPL Table 1 in response to FERC’s Order RM0616-009 which required the ERO to clarify TPL-002-0, Table 1 - footnote ‘b’, regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a
transmission system. Such clarification was originally required by June 30, 2010. Table 1 is
used in TPL-001, TPL-002, TPL-003, and TPL-004 – and any change to Table 1 needs to be
reflected in all four of these TPL standards. (Note: FERC issued a clarifying order on June 11,
2010 which extended the deadline for clarifying Table 1 until March 31, 2011.)
Based on stakeholder comments, the drafting team has made changes from the initial ballot
posting to Footnote ‘b’ in Table 1 of TPL-001, TPL-002, TPL-003, and TPL-004. The changes
include the following:
Stakeholders identified that the terminology used in Footnote ‘b’ didn’t match the terminology
used in the associated column heading of Table 1 – ‘Loss of Demand or Curtailed Firm
Transfers.’ For additional clarity, the team made the following terminology changes:
•

The term ‘Load’ was replaced with ‘Demand’

•

The term ‘Firm Transmission Service’ was replaced with ‘firm transfers’

While the initial ballot results came close to the required approval percentage, it was clear to the
SDT that there were still a number of concerns with the proposed clarification. In particular,
entities were concerned that the proposal was still unclear and too limiting on the proposed
conditions when Demand could be interrupted. Also, there were numerous concerns raised on
jurisdictional issues with regard to interrupting Demand. In short, the needed clarification hadn’t
been achieved. Therefore, the SDT continued discussions on different alternatives to address the
needed clarification. This led the SDT to focus on identifying constraining parameters such as
the amount of Demand that could be interrupted, annual amount of exposure, etc.

Adopted by NERC Board of Trustees: February 8, 2005
1 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts

In order to receive additional industry feedback on the new approach, a Technical Conference
was held on August 10, 2010 to address four specific questions arising from the FERC June 11,
2010 clarification order. These 4 questions were:
1. Under what circumstances do you believe the existing footnote ‘b’ allows an
entity to plan to shed non-consequential firm load for a single contingency
(Category B)? Please provide specific information to the extent possible.
2. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be applied at
the fringes of a system. Is this limitation appropriate and if so, please define it?
What other specific criteria could be applied to limit the planned use of nonconsequential firm load loss for a single contingency (Category B)?
3. If footnote ‘b’ were re-stated such that there would be no planned loss of nonconsequential firm load allowed for a single contingency event (Category B),
what changes to your transmission plan would be required? Please quantify your
response to the extent possible.
4. The June 11th order from FERC suggested that planning to shed nonconsequential firm load for a single contingency (Category B) could be handled
on a case-by-case basis with affected entities asking for an exception from the
ERO. Could you support such a process? If your response is no, then what
process would you suggest? If your response is yes, then what technical criteria
should be developed to identify and evaluate cases?
In summary, the SDT heard that:
•
•
•
•

Industry feels that interrupting non-consequential Demand was appropriate in certain
limited circumstances and that such usage was not widespread.
Use of the term ‘fringes’ was seen as problematic and application at the ‘fringes’ could
possibly be discriminatory.
If interruption of non-consequential Demand was not allowed, such a policy would result
in significant costs to customers for limited benefits.
A case-by-case exception process that required ERO or FERC approval was not viewed
as an acceptable approach due to possible inconsistencies in approach and potential
unacceptable delays.

The SDT took in all of these inputs and returned to their deliberations attempting to leverage the
existing work with the industry comments to develop an acceptable clarification to footnote ‘b’.
This led to the approach shown in this posting where the SDT has taken the concept of allowing
interruption of Demand without numerical constraints in an open and transparent stakeholder
process to review and accept such plans. This open and transparent stakeholder process is seen as
an enhancement of existing entity processes without the problems associated with an ERO or
FERC case-by-case exception process.
The SDT believes that this approach addresses industry concerns and FERC Order 693 directives
(and subsequent orders) concerning clarification to footnote ‘b’ in a way that is an equal and
effective method and that should be acceptable to all concerned parties.
Adopted by NERC Board of Trustees: February 8, 2005
2 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts

In addition, the following bullet was added to Footnote ‘b’ to clarify that it is always acceptable
to use Interruptible Demand and Demand-Side Management:
•

Interruptible Demand or Demand-Side Management

These changes were balloted and received approval but several commenters requested
clarifications of the SDT’s intent. The SDT responded to these requests by re-ordering the items
in footnote ’b’ to make it clear exactly what the intent of the changes were.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2011

2. Submit to BOT for approval

January 2011

3. File with FERC

February 2011

Adopted by NERC Board of Trustees: February 8, 2005
3 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
A. Introduction
1.

Title:
System Performance Following Extreme Events Resulting in the Loss of Two or
More Bulk Electric System Elements (Category D)

2.

Number:

3.

Purpose: System simulations and associated assessments are needed periodically to ensure that
reliable systems are developed that meet specified performance requirements, with sufficient
lead time and continue to be modified or upgraded as necessary to meet present and future
System needs.

4.

Applicability:

TPL-004-01

4.1. Planning Authority
4.2. Transmission Planner
5.

Effective Date:

April 1, 2005

5.

Effective Date:
The application of revised Footnote ‘b’ in Table 1 will take effect on the
first day of the first calendar quarter, 60 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is evaluated for the risks
and consequences of a number of each of the extreme contingencies that are listed under
Category D of Table I. To be valid, the Planning Authority’s and Transmission Planner’s
assessment shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five).

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category D contingencies of Table I. The specific elements selected (from within
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category D contingencies that
would produce the more severe system results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by the
responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.
R1.3.4. Have all projected firm transfers modeled.

Adopted by NERC Board of Trustees: February 8, 2005
4 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
R1.3.5. Include existing and planned facilities.
R1.3.6. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.7. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.8. Include the effects of existing and planned control devices.
R1.3.9. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.
R1.4.

Consider all contingencies applicable to Category D.

R2. The Planning Authority and Transmission Planner shall each document the results of its
reliability assessments and shall annually provide the results to its entities’ respective NERC
Regional Reliability Organization(s), as required by the Regional Reliability Organization.
C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment for its system
responses as specified in Reliability Standard TPL-004-01_R1.
M2. The Planning Authority and Transmission Planner shall provide evidence to its Compliance
Monitor that it reported documentation of results of its reliability assessments per Reliability
Standard TPL-004-01_R1.
D. Compliance
1.

2.

B.

Compliance Monitoring Process
1.1.

Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organization.
Each Compliance Monitor shall report compliance and violations to NERC via the
NERC Compliance Reporting Process.

1.2.

Compliance Monitoring Period and Reset Timeframe
Annually.

1.3.

Data Retention
None specified.

1.4.

Additional Compliance Information
None.

Levels of Non-Compliance
2.1.

Level 1:
A valid assessment, as defined above, for the near-term planning horizon
is not available.

2.2.

Level 2:

Not applicable.

2.3.

Level 3:

Not applicable.

2.4.

Level 4:

Not applicable.

Regional Differences

Adopted by NERC Board of Trustees: February 8, 2005
5 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

1

TBD

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

Adopted by NERC Board of Trustees: February 8, 2005
6 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-01 — S ys te m P e rfo rm a n ce Fo llowin g Extre m e BES Eve n ts
Table I. Transmission System Standards – Normal and Emergency Conditions

Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Adopted by NERC Board of Trustees: February 8, 2005
7 of 9
Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-00a — S ys te m P e rfo rm a n c e Fo llowing Extre m e BES Eve n ts

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

4. Bus Section

Evaluate for risks and
consequences.



e

3Ø Fault, with Normal Clearing :
5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)
9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or System Voltage Limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1) directly
served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to address BES
performance requirements. When interruption of Firm Demand is utilized within the planning process to address BES
performance requirements, such interruption is limited to circumstances where the use of Demand interruption are
documented, including alternatives evaluated; and where the Demand interruption is subject to review in an open and
transparent stakeholder process that includes addressing stakeholder comments.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
Adopted by NERC Board of Trustees: February 8, 2005
8 of 9

Effective Date: April 1, 2005

Draft 5: January 26, 2011

S ta n d a rd TP L-004-00a — S ys te m P e rfo rm a n c e Fo llowing Extre m e BES Eve n ts

f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Adopted by NERC Board of Trustees: February 8, 2005
9 of 9

Effective Date: April 1, 2005

Draft 5: January 26, 2011

Standards Announcement
Recirculation Ballot Window Open January 26-February 5, 2011
Project 2010-11 TPL Table 1 Order
Now available at: https://standards.nerc.net/CurrentBallots.aspx
A recirculation ballot window for standards TPL-001-1, TPL-002-1b, TPL-003-1a, and TPL-004-1 is open until
8 p.m. Eastern on Saturday, February 5, 2011.
Instructions
Members of the ballot pool associated with this project may log in and submit their votes from the following
page: https://standards.nerc.net/CurrentBallots.aspx.
Ballot Process
The Standards Committee encourages all members of the ballot pool to review the consideration of comments
submitted during the last ballot window. In the recirculation ballot, votes are counted by exception only — if a
ballot pool member does not submit a revision to that member’s original vote, the vote remains the same as in
the first ballot. Members of the ballot pool may:
•

Reconsider and change their votes from the first ballot

•

Vote in the second ballot even if they did not vote on the first ballot

•

Take no action if they do not want to change their original vote

Additional Information
The Standard Processes Manual allows drafting teams to make changes following an initial or successive ballot
with a goal of improving the quality of a standard, provided those changes do not alter the applicability or scope
of the proposed standard. Following the initial ballot the Project 2010-11 made minor changes to the structure
of footnote ‘b’ in all of the standards, and corrected capitalization of NERC Glossary terms. The standards
(clean versions, and redlines against the last posted and last approved versions) have been posted on the project
page.
Next Steps
Voting results will be posted and announced after the ballot window closes. If approved, the standards and
associated implementation plan will be submitted to the Board of Trustees.
Background
FERC Order RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1 - footnote ‘b,’ regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a transmission
system and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive, a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision

achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011; thus the project is no longer considered “Urgent
Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
•

TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)

•

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category
B)

•

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

•

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More
Bulk Electric System Elements (Category D)

More details may be found on the project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

Standards Announcement
Project 2010-11 TPL Table 1, Footnote B
Recirculation Ballot Results
Now available at: https://standards.nerc.net/Ballots.aspx
A recirculation ballot of Table 1 footnote ‘b’ in TPL-001-1 through TPL-004-1 ended on February 5, 2011. The
standards were approved. Voting statistics are listed below, and the Ballot Results Web page provides a link to
the detailed results:
Quorum: 93.61 %
Approval: 86.54 %
Background:
FERC Order RM06-16-009 requires the ERO to clarify TPL-002-0, Table 1 - footnote ‘b,’ regarding the
planned or controlled interruption of electric supply where a single contingency occurs on a transmission
system, and originally directed NERC to file the revised standards by June 30, 2010. To meet this directive a
proposed revision was posted for “Urgent Action” and balloted from May 17-27, 2010. The proposed revision
achieved a quorum (84%) and almost enough affirmative votes (64%) to achieve weighted segment approval;
however many balloters provided comments indicating the need for additional modifications. Following the
initial ballot, FERC extended the due date to March 31, 2011, thus the project is no longer considered “Urgent
Action.”
Because Table 1 appears in TPL-001, TPL-002, TPL-003, and TPL-004, the change is reflected in all four
standards:
•

TPL-001-1 - System Performance Under Normal (No Contingency) Conditions (Category A)

•

TPL-002-1b - System Performance Following Loss of a Single Bulk Electric System Element (Category
B)

•

TPL-003-1a - System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

•

TPL-004-1 - System Performance Following Extreme Events Resulting in the Loss of Two or More
Bulk Electric System Elements (Category D)

More details may be found on the project page:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html

Next Steps
The standards will go to the Board of Trustees for adoption.
Standards Process
The Standard Processes Manual contains all the procedures governing the standards development process. The
success of the NERC standards development process depends on stakeholder participation. We extend our
thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 609.452.8060.
North American Electric Reliability Corporation
116-390 Village Blvd.
Princeton, NJ 08540
609.452.8060 | www.nerc.com

NERC Standards

 

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User Name

Ballot Results

Ballot Name: Project 2010-11 TPL Table 1 Footnote B SAR_rc

Password

Ballot Period: 1/26/2011 - 2/5/2011
Ballot Type: recirculation

Log in

Total # Votes: 293

Register
 

Total Ballot Pool: 313
Quorum: 93.61 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
86.54 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
95
11
66
26
58
37
0
8
4
8
313

#
Votes

 
1
1
1
1
1
1
0
0.5
0.4
0.7
7.6

#
Votes

Fraction
 

68
7
50
16
40
28
0
5
4
7
225

Negative
Fraction

 
0.829
0.7
0.833
0.889
0.851
0.875
0
0.5
0.4
0.7
6.577

Abstain
No
# Votes Vote

 
14
3
10
2
7
4
0
0
0
0
40

 
0.171
0.3
0.167
0.111
0.149
0.125
0
0
0
0
1.023

 
7
1
5
6
5
3
0
1
0
0
28

6
0
1
2
6
2
0
2
0
1
20

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
Allegheny Power
Ameren Services
American Electric Power
American Transmission Company, LLC
APS
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy

Member
 
Rodney Phillips
Kirit S. Shah
Paul B. Johnson
Andrew Z Pusztai
Barbara McMinn
Robert D Smith
John Bussman
James Armke

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f88bbf54-2bd7-4290-94b4-3c8fb88ffe6f[2/9/2011 4:02:06 PM]

Ballot
 
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

Comments
 
View

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Avista Corp.
BC Transmission Corporation
Beaches Energy Services
Black Hills Corp
Bonneville Power Administration
CenterPoint Energy
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Vero Beach
City Utilities of Springfield, Missouri
Clark Public Utilities
Cleco Power LLC
Colorado Springs Utilities
Consolidated Edison Co. of New York
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
East Kentucky Power Coop.
Empire District Electric Co.
Entergy Corporation
FirstEnergy Energy Delivery
Florida Keys Electric Cooperative Assoc.
Gainesville Regional Utilities
GDS Associates, Inc.
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
KAMO Electric Cooperative
Kansas City Power & Light Co.
Keys Energy Services
Lakeland Electric
Lincoln Electric System
Lone Star Transmission, LLC
Lower Colorado River Authority
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
National Grid
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York State Electric & Gas Corp.
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Orlando Utilities Commission
Pacific Gas and Electric Company
PacifiCorp
PECO Energy
Platte River Power Authority
Potomac Electric Power Co.
PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Progress Energy Carolinas
Public Service Company of New Mexico

Scott Kinney
Gordon Rawlings
Joseph S. Stonecipher
Eric Egge
Donald S. Watkins
Paul Rocha
Kevin L Howes

Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative

Chang G Choi

Affirmative

Randall McCamish
Jeff Knottek
Jack Stamper
Danny McDaniel
Paul Morland
Christopher L de Graffenried
Robert W. Roddy
Hertzel Shamash
James Tucker
John K Loftis
Douglas E. Hils
George S. Carruba
Ralph Frederick Meyer
George R. Bartlett
Robert Martinko
Dennis Minton
Luther E. Fair
Claudiu Cadar
Harold Taylor, II
Gordon Pietsch

Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative

Robert Solomon

Affirmative

Ajay Garg
Bernard Pelletier
Ronald D. Schellberg

Affirmative
Affirmative
Affirmative

Michael Moltane

Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Negative

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Walter Kenyon
Michael Gammon
Stan T. Rzad
Larry E Watt
Doug Bantam
Julius Horvath
Martyn Turner
Joe D Petaski
Danny Dees
Terry Harbour
Saurabh Saksena
Richard L. Koch

Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain

View

Randy MacDonald

Negative

View

Negative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

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Raymond P Kinney
David H. Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Douglas G Peterchuck
Michael T. Quinn
Brad Chase
Chifong L. Thomas
Colt Norrish
Ronald Schloendorn
John C. Collins
David Thorne
Larry D. Avery
Brenda L Truhe
Sammy Roberts
Laurie Williams

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NERC Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
2

Public Service Electric and Gas Co.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
SCE&G
Seattle City Light
Snohomish County PUD No. 1
South Texas Electric Cooperative
Southern California Edison Co.
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Southwestern Power Administration
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Western Area Power Administration
Xcel Energy, Inc.
Alberta Electric System Operator

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool
Alabama Power Company
Allegheny Power
Ameren Services
APS
Arkansas Electric Cooperative Corporation
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Black Hills Power
Bonneville Power Administration
City of Austin dba Austin Energy
City of Bartow, Florida
City of Clewiston
City of Green Cove Springs
City of Leesburg
Cleco Corporation
ComEd
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources Services
Duke Energy Carolina
East Kentucky Power Coop.
Entergy
FirstEnergy Solutions
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Hydro One Networks, Inc.
JEA

Kenneth D. Brown
John C. Allen
Tim Kelley
Robert Kondziolka
Linda Brown
Terry L. Blackwell
Henry Delk, Jr.
Pawel Krupa
Long T Duong
Richard McLeon
Dana Cabbell
Horace Stephen Williamson
William G. Hutchison
James L. Jones
Gary W Cox
Noman Lee Williams
Beth Young
Larry Akens
Keith V Carman
John Tolo
Jonathan Appelbaum
Brandy A Dunn
Gregory L Pieper
Mark B Thompson
Venkataramakrishnan
Vinnakota
Gregory Van Pelt
Chuck B Manning
Kim Warren
Kathleen Goodman
Jason L Marshall
Alden Briggs
Gregory Campoli
Tom Bowe
Charles H Yeung
Richard J. Mandes
Bob Reeping
Mark Peters
Steven Norris
Philip Huff
James V. Petrella
Robert Lafferty
Pat G. Harrington
Andy Butcher
Rebecca Berdahl
Andrew Gallo
Matt Culverhouse
Lynne Mila
Gregg R Griffin
Phil Janik
Michelle A Corley
Bruce Krawczyk
Peter T Yost
David A. Lapinski
Russell A Noble
Michael R. Mayer
Kent Kujala
Michael F Gildea
Henry Ernst-Jr
Sally Witt
Joel T Plessinger
Kevin Querry
Lee Schuster
Anthony L Wilson
R Scott S. Barfield-McGinnis
David L Kiguel
Garry Baker

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Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative

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Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
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Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative

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NERC Standards
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3
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3
3
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3
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3
3
3
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3
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4
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4
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4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5

Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Louisville Gas and Electric Co.
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northern Indiana Public Service Co.
Orlando Utilities Commission
Owensboro Municipal Utilities
PacifiCorp
Platte River Power Authority
Potomac Electric Power Co.
Progress Energy Carolinas
Public Service Electric and Gas Co.
Public Utility District No. 1 of Chelan County
Sacramento Municipal Utility District
Salt River Project
San Diego Gas & Electric
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
South Carolina Electric & Gas Co.
Southern California Edison Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Xcel Energy, Inc.
Alliant Energy Corp. Services, Inc.
American Municipal Power - Ohio
American Public Power Association
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of Clewiston
City Utilities of Springfield, Missouri
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
LaGen
Modesto Irrigation District
Ohio Edison Company
Oklahoma Municipal Power Authority
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tallahassee Electric
Wisconsin Energy Corp.
 
AEP Service Corp.
Amerenue
APS
Avista Corp.
BC Hydro and Power Authority

Charles Locke
Gregory David Woessner
Mace Hunter
Bruce Merrill
Charles A. Freibert
Greg C. Parent
Thomas C. Mielnik
Don Horsley
John S Bos
Tony Eddleman
Marilyn Brown
Michael Schiavone
William SeDoris
Ballard Keith Mutters
Thomas T Lyons
John Apperson
Terry L Baker
Robert Reuter
Sam Waters
Jeffrey Mueller
Kenneth R. Johnson
James Leigh-Kendall
John T. Underhill
Scott Peterson
Zack Dusenbury
Dana Wheelock
James R Frauen
Hubert C. Young
David Schiada
Travis Metcalfe
Ronald L Donahey
Ian S Grant
Janelle Marriott
Michael Ibold
Kenneth Goldsmith
Kevin Koloini
Allen Mosher
Ronnie Frizzell
Duane S Dahlquist
Reza Ebrahimian
Kevin McCarthy
John Allen
David Frank Ronk
Rick Syring
Daniel Herring
Frank Gaffney
Thomas W. Richards
Guy Andrews
Richard Comeaux
Spencer Tacke
Douglas Hohlbaugh
Terri Pyle
Henry E. LuBean

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative

John D. Martinsen

Affirmative

Mike Ramirez
Hao Li
Steven R Wallace
Keith Morisette
Allan Morales
Anthony Jankowski
Edwin B Cano
Brock Ondayko
Sam Dwyer
Mel Jensen
Edward F. Groce
Clement Ma

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain

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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Negative
Affirmative
Abstain

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NERC Standards
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5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6

Black Hills Corp
Bonneville Power Administration
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Cleco Power
Consolidated Edison Co. of New York
Consumers Energy
Cowlitz County PUD
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy
East Kentucky Power Coop.
Electric Power Supply Association
Energy Northwest - Columbia Generating
Station
Entergy Corporation
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
MidAmerican Energy Co.
Nebraska Public Power District
New York Power Authority
Northern California Power Agency
Northern Indiana Public Service Co.
Omaha Public Power District
Orlando Utilities Commission
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
Progress Energy Carolinas
PSEG Power LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Southern Company Generation
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Wisconsin Public Service Corp.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
Arizona Public Service Co.
Bonneville Power Administration
City of Austin dba Austin Energy
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy Carolina
Entergy Services, Inc.
Exelon Power Team
FirstEnergy Solutions

George Tatar
Francis J. Halpin

Affirmative
Affirmative

Max Emrick

Affirmative

Alan Gale
Stephanie Huffman
Wilket (Jack) Ng
James B Lewis
Bob Essex
Christy Wicke
Mike Garton
Dale Q Goodwine
Stephen Ricker
Jack Cashin

Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Doug Ramey

Affirmative

Stanley M Jaskot
Michael Korchynsky
Kenneth Dresner
David Schumann
Donald Gilbert
Scott Heidtbrink
Mike Blough
Thomas J Trickey
Dennis Florom
S N Fernando
Christopher Schneider
Don Schmit
Gerald Mannarino
Tracy R Bibb
Michael K Wilkerson
Mahmood Z. Safi
Richard Kinas
Sandra L. Shaffer
Pete Ungerman
Gary L Tingley
Annette M Bannon
Wayne Lewis
Jerzy A Slusarz
Bethany Hunter
Glen Reeves
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Richard Jones
William D Shultz
RJames Rocha
Scott M. Helyer
George T. Ballew
Melissa Kurtz
Martin Bauer P.E.
Leonard Rentmeester
Liam Noailles
Edward P. Cox
Jennifer Richardson
Justin Thompson
Brenda S. Anderson
Lisa L Martin
Robert Hirchak
Nickesha P Carrol
Brenda Powell
Louis S. Slade
Walter Yeager
Terri F Benoit
Pulin Shah
Mark S Travaglianti

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Affirmative
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Affirmative
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Affirmative
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Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Abstain
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

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NERC Standards
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8
8
8
8
8
8
8
8
9
9
9
9
10
10
10
10
10
10
10
10
 

Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Manitoba Hydro
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
Progress Energy
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
 
INTELLIBIND
JDRJC Associates
Transmission Strategies, LLC
Utility Services, Inc.
Volkmann Consulting, Inc.
California Energy Commission
Commonwealth of Massachusetts Department
of Public Utilities
Oregon Public Utility Commission
Snohomish County PUD No. 1
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council, Inc.
ReliabilityFirst Corporation
SERC Reliability Corporation
Southwest Power Pool Regional Entity
Texas Reliability Entity
Western Electricity Coordinating Council

Richard L. Montgomery
Thomas E Washburn
Silvia P. Mitchell
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Daniel Prowse
Joseph O'Brien
David Ried
Scott L Smith
Carol Ballantine
Mark A Heimbach
John T Sturgeon
James D. Hebson
Claire Warshaw
Mike Hummel
Suzanne Ritter
Dennis Sismaet
Trudy S. Novak
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative

Peter H Kinney

Affirmative

David F. Lemmons
Roger C Zaklukiewicz
James A Maenner
Edward C Stein
Kevin Conway
Jim D. Cyrulewski
Bernie M Pasternack
Brian Evans-Mongeon
Terry Volkmann
William Mitchell Chamberlain

Affirmative

Affirmative
Affirmative
Abstain
Affirmative
Affirmative

Donald E. Nelson

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

A New Jersey Nonprofit Corporation

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Affirmative

Jerome Murray
William Moojen
James D Burley
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B Edge
Stacy Dochoda
Larry D Grimm
Louise McCarren
 

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Standard TPL-001-3 — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions
1. Initial posting

Anticipated Date
July 2012

2. Recirculation ballot

October 2012

3. BOT approval

February 2013

Draft 1: July 31, 2012

1

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 1: July 31, 2012

2

Standard TPL-001-3 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-3a

4.1. Functional Entity

5.

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 no regulatory approval is required, Requirements R1 and R7 become
effective on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption.
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 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.
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 required on the
first day of the first calendar quarter 84 months after Board of Trustees adoption, Corrective
Action Plans applying to the following categories of Contingencies and events identified in
TPL-001-3, 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-001-3:










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)

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

Draft 1: July 31, 2012

3

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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 :

2.1.5.

Draft 1: July 31, 2012

•
•
•
•
•
•

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.
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,
4

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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.
2.2.

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.

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 time frame 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:

Draft 1: July 31, 2012

5

Standard TPL-001-3 — Transmission System Planning Performance 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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required time frame, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the
use of Non-Consequential Load Loss or curtailment of Firm Transmission
Service.

Draft 1: July 31, 2012

6

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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
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.

Draft 1: July 31, 2012

The Planning Coordinator and Transmission Planner shall coordinate with
adjacent Planning Coordinators and Transmission Planners to ensure that
7

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Contingencies on adjacent Systems which may impact their Systems are
included in the Contingency list.
3.5.

R4.

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

4.3.2.

Draft 1: July 31, 2012

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

Simulate the expected automatic operation of existing and planned devices
designed to provide dynamic control of electrical system quantities when
8

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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.
4.4.

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.

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.

Draft 1: July 31, 2012

9

Standard TPL-001-3 — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft 1: July 31, 2012

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-3 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft 1: July 31, 2012

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-3 — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft 1: July 31, 2012

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-3 — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft 1: July 31, 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-3 — 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 be to minimize the likelihood and magnitude of Non-Consequential Load Loss following Contingency events.
However, in limited circumstances Non-Consequential Load Loss may be needed to ensure that BES performance requirements are met. When NonConsequential Load Loss is utilized within the planning process to address BES performance requirements, such interruption is limited to circumstances
where the Non-Consequential Load Loss is meets the conditions shown in Attachment 1. In no case can the planned Firm Demand interruption under
footnote 12 exceed ‘x’ MW.
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).
Draft 1: July 31, 2012

14

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption 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 shall document the stakeholder process which shall include the
following:
1. Meetings must be open to all 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 all 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 applications of the planned Firm Demand interruption under footnote 12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption 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.

II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Firm Demand interruption under
footnote 12 which must include the following:
1. Conditions under which Firm Demand interruption 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An assessment of the use of Firm Demand interruption under footnote 12 on the
health, safety, and welfare of the community
3. Estimated frequency of Firm Demand interruption under footnote 12 based on historical
performance.
Draft 1: July 31, 2012

Standard TPL-001-3 — Transmission System Planning Performance Requirements

4. Expected duration of Firm Demand interruption under footnote 12 based on historical
performance.
5. Future plans to mitigate the need for Firm Demand interruption under footnote 12.
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 12.
7. Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote 12.
8. Assessment of potential overlapping uses of footnote 12 with adjacent planners.

III. Instances for which Approval of Interruptions of Firm Demand under footnote 12 is Required
Approval of the use of Firm Demand interruption under footnote 12 by the applicable regulatory
authority or governing body responsible for retail electric service issues is required 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 Firm Demand interruptions under footnote 12
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 Firm Demand interruption under footnote 12 is greater than or equal to 25
MW.
Before a Firm Demand interruption under footnote 12 is allowed to be utilized as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues. In no case can the planned Firm
Demand interruption under footnote 12 exceed x MW.
When approval for the use of a footnote 12 Firm Demand interruption is necessary under items
III.1 or III.2 above, the Planning Coordinator or Transmission Planner must submit the
information outlined in items II.1 through II.8 above to the Regional Entity. Within 45 days of
receipt of this information, the Regional Entity must review each proposed use of Firm Demand
interruption under footnote 12 to verify that there are no Adverse Reliability Impacts including
any potential cumulative effect within the Regional Entity’s footprint. If the Regional Entity
states that an Adverse Reliability Impact will result due to the requested Firm Demand
interruption, then the requesting entity may appeal the decision to the ERO. Regional Entity
determinations of Adverse Reliability Impacts are to be evaluated by the Regional Entity through
a published methodology approved by the ERO.

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Standard TPL-001-3 — 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 Time frame
Not applicable.

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Standard TPL-001-3 — 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
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Standard TPL-001-3 — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 1: July 31, 2012

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.

19

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 1: July 31, 2012

20

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 1: July 31, 2012

21

Standard TPL-001-3 — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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-001-3; and retirement of TPL-005-0 and TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed Attachment 1 pursuant to FERC
Order RM06-16-009

Revised

Draft 1: July 31, 2012

Action

Change Tracking

22

Standard TPL-001-23 — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions
1. Initial posting

Anticipated Date
July 2012

2. Recirculation ballot

October 2012

3. BOT approval

February 2013

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-23a

4.1. Functional Entity

5.

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 no regulatory approval is required, Requirements R1
and R7 become effective on the first day of the first calendar quarter, 12 months after Board of
Trustees adoption.
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 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.
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 required on the
first day of the first calendar quarter 84 months after Board of Trustees adoption, Corrective
Action Plans applying to the following categories of Contingencies and events identified in
TPL-001-23, 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-001-23:










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)

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

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance Requirements

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 :

2.1.5.

•
•
•
•
•
•

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.
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,

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance Requirements

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.
2.2.

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.

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 timeframetime frame 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:

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance 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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframetime frame, then the Transmission Planner or
Planning Coordinator is permitted to utilize Non-Consequential Load Loss
and curtailment of Firm Transmission Service to correct the situation that
would normally not be permitted in Table 1, provided that the Transmission
Planner or Planning Coordinator documents that they are taking actions to
resolve the situation. The Transmission Planner or Planning Coordinator
shall document the situation causing the problem, alternatives evaluated, and
the use of Non-Consequential Load Loss or curtailment of Firm
Transmission Service.

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Draft 1:

Standard TPL-001-23 — Transmission System Planning Performance Requirements

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
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.

The Planning Coordinator and Transmission Planner shall coordinate with
adjacent Planning Coordinators and Transmission Planners to ensure that

Adopted by NERC Board of Trustees: August 4, 2011

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Standard TPL-001-23 — Transmission System Planning Performance Requirements

Contingencies on adjacent Systems which may impact their Systems are
included in the Contingency list.
3.5.

R4.

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

4.3.2.

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

Simulate the expected automatic operation of existing and planned devices
designed to provide dynamic control of electrical system quantities when

Adopted by NERC Board of Trustees: August 4, 2011

Draft 1:

Standard TPL-001-23 — Transmission System Planning Performance Requirements

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.
4.4.

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.

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: LowerMedium] [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: LowerLow] [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.

Adopted by NERC Board of Trustees: August 4, 2011

Draft 1:

Standard TPL-001-23 — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

BES Level

3

SLG

Opening of a line section w/o a fault

7

N/A

Bus Section Fault

No

SLG

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

2

8

4. Internal Breaker Fault (Bus-tie Breaker)

Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

Standard TPL-001-23 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

Standard TPL-001-23 — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Event

1

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, 2011Draft7: July 2012

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

Standard TPL-001-23 — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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-001-23 — 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 be to minimize the likelihood and magnitude of Non-Consequential Load Loss following Contingency events.
However, in limited circumstances Non-Consequential Load Loss may be needed to addressensure that BES performance requirements are met. When
Non-Consequential Load Loss is utilized within the planning process 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 Firm Demand interruption under footnote 12 exceed ‘x’ MW.
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).
Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption 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 shall document the stakeholder process which shall include the
following:
1. Meetings must be open to all 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 all 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 applications of the planned Firm Demand interruption under footnote 12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption 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.

II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Firm Demand interruption under
footnote 12 which must include the following:
1. Conditions under which Firm Demand interruption 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An assessment of the use of Firm Demand interruption under footnote 12 on the
health, safety, and welfare of the community
Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

3. Estimated frequency of Firm Demand interruption under footnote 12 based on historical
performance.
4. Expected duration of Firm Demand interruption under footnote 12 based on historical
performance.
5. Future plans to mitigate the need for Firm Demand interruption under footnote 12.
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 12.
7. Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote 12.
8. Assessment of potential overlapping uses of footnote 12 with adjacent planners.

III. Instances for which Approval of Interruptions of Firm Demand under footnote 12 is Required
Approval of the use of Firm Demand interruption under footnote 12 by the applicable regulatory
authority or governing body responsible for retail electric service issues is required 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 Firm Demand interruptions under footnote 12
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 Firm Demand interruption under footnote 12 is greater than or equal to 25
MW.
Before a Firm Demand interruption under footnote 12 is allowed to be utilized as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues. In no case can the planned Firm
Demand interruption under footnote 12 exceed x MW.
When approval for the use of a footnote 12 Firm Demand interruption is necessary under items
III.1 or III.2 above, the Planning Coordinator or Transmission Planner must submit the
information outlined in items II.1 through II.8 above to the Regional Entity. Within 45 days of
receipt of this information, the Regional Entity must review each proposed use of Firm Demand
interruption under footnote 12 to verify that there are no Adverse Reliability Impacts including
any potential cumulative effect within the Regional Entity’s footprint. If the Regional Entity
states that an Adverse Reliability Impact will result due to the requested Firm Demand
interruption, then the requesting entity may appeal the decision to the ERO. Regional Entity
determinations of Adverse Reliability Impacts are to be evaluated by the Regional Entity through
a published methodology approved by the ERO.

Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Standard TPL-001-23 — 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 TimeframeTime frame
Not applicable.

Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Standard TPL-001-23 — 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
Adopted by NERC Board of Trustees: August 4, 2011Draft7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Adopted by NERC Board of Trustees: August 4, 2011

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.

Draft 7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Adopted by NERC Board of Trustees: August 4, 2011

Draft 7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Adopted by NERC Board of Trustees: August 4, 2011

Draft 7: July 2012

Standard TPL-001-23 — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

Action

0

April 1, 2005

Effective Date

New

0

February 8, 2005

BOT Approval

Revised

0

June 3, 2005

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

Errata

0

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,
201103/17/2
001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of TrusteesRevised footnote ‘b’ pursuant
to FERC Order RM06-16-009

Revised (Project 201011)2006-02 – revision to
address FERC directive

2

August 4,
2011To be
Determined

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-001-23; and retirement of TPL-005-0 and
TPL-006-0.

Project 2006-02 –
complete revision

22a

August 4,
2011Februar
y 2013

Adopted by Board of TrusteesAddress remand of proposed
Attachment 1 pursuant to FERC Order RM06-16-009

Revised

Adopted by NERC Board of Trustees: August 4, 2011

Change Tracking

Draft 7: July 2012

S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial posting

July 2012

2. Recirculation ballot

October 2012

3. BOT approval

February 2013

Draft 1: July 31, 2012

Page 1 of 14

S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1c

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Draft 1: July 31, 2012

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1, Requirement R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1, Requirement R1 and TPL-002-1,
Requirement R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1, Requirement R3.

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S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

1c

February 2013

Address remand of proposed footnote ‘b’
pursuant to FERC Order RM06-16-009

Revised

Draft 1: July 31, 2012

Page 4 of 14

S ta n d a rd TP L-002-1b — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 1: July 31, 2012

Page 5 of 14

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
ensure that BES performance requirements are met. When interruption of Firm Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1. In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed ‘x’ MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 1: July 31, 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ is reviewed through an open and transparent
stakeholder process. The responsible entity shall document the stakeholder process which shall
include the following:
1. Meetings must be open to all 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 all 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 applications of the planned Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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

II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An assessment of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on historical
performance
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on historical
performance
5. Future plans to mitigate the need for Firm Demand interruption under footnote ‘b’
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
7. Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote ‘b’
8. Assessment of potential overlapping uses of footnote ‘b’ with adjacent planners

III. Instances for which Approval of Interruptions of Firm Demand under Footnote ‘b’ is
Required
Approval of the use of Firm Demand interruption under footnote ‘b’ by the applicable regulatory
authority or governing body responsible for retail electric service issues is required 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 Firm Demand interruptions under footnote ‘b’
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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW.
Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an element of
a Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed x MW.
When approval for the use of a footnote ‘b’ Firm Demand interruption is necessary under
items III.1 or III.2 above, the Planning Coordinator or Transmission Planner must submit
the information outlined in items II.1 through II.8 above to the Regional Entity. Within 45
days of receipt of this information, the Regional Entity must review each proposed use of
Firm Demand interruption under footnote ‘b’ to verify that there are no Adverse Reliability
Impacts including any potential cumulative effect within the Regional Entity’s footprint. If
the Regional Entity states that an Adverse Reliability Impact will result due to the
requested Firm Demand interruption, then the requesting entity may appeal the decision to

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

the ERO. Regional Entity determinations of Adverse Reliability Impacts are to be
evaluated by the Regional Entity through a published methodology approved by the ERO.

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial posting

July 2012

2. Recirculation ballot

October 2012

3. BOT approval

February 2013

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-0b1cb

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: Immediately after approval of applicable regulatory authorities.

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after applicable regulatory approval. In those jurisdictions
where no regulatory approval is required, the effective date will be the first day of the first calendar
quarter, 60 months after Board of Trustees adoption. All other requirements remain in effect per
previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories,,, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-0_1, Requirement R1, the Planning Authority and Transmission
Planner shall each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-0_1, Requirement R1 and TPL-002-0_1,
Requirement R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-0_1, Requirement R3.

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D. Compliance
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

0b1b

Date

Action

Change Tracking

0

February 8,
2005

Adopted by NERC Board of Trustees

New

0

April 1, 2005

Effective Date

New

0a

July 30October
23, 2008

Adopted by NERC Board of TrusteesAdded
Appendix 1 – Interpretation of TPL-002-0
Requirements R1.3.2 and R1.3.12 and TPL003-0 Requirements R1.3.2 and R1.3.12 for
Ameren and MISO

NewRevised

0a0b

October 23,
2008November
5, 2009

Added Appendix 12 – Interpretation of
TPL-002-0 Requirements R1.3.2 and
R1.3.12 and TPL-003-0 Requirements
R1.3.2 and R1.3.12 for Ameren and MISO
10 approved by BOT on November 5, 2009

RevisedAddition

November 5,

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,

InterpretationRevised

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0b1c

2009April 2010

2009Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

September 15,
2011February
2013

FERC Order issued approving the
Interpretation of R1.3.10 (FERC Order
becomes effective October 24,
2011)Address remand of proposed footnote
‘b’ pursuant to FERC Order RM06-16-009

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Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) Planned or controlled interruption of electric supply to radial customers or some local Network customers, connected to or
supplied by the Faulted element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems. To prepare for the next contingency, system adjustments are
permitted, including curtailments of contracted Firm (non-recallable reserved) electric power Transfers.
b) An objective of the planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or
Demand-Side Management Load. Furthermore, in limited circumstances Firm Demand may need to be interrupted to
ensure that BES performance requirements are met. When interruption of Firm Demand is utilized within the planning
process to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1. In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed ‘x’ MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ is reviewed through an open and transparent
stakeholder process. The responsible entity shall document the stakeholder process which shall
include the following:
1. Meetings must be open to all 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 all 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 applications of the planned Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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

II. Information for Inclusion in Item #3 of the Stakeholder Process
The responsible entity shall document the planned use of Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An assessment of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community

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3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on historical
performance
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on historical
performance
5. Future plans to mitigate the need for Firm Demand interruption under footnote ‘b’
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
7. Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote ‘b’
8. Assessment of potential overlapping uses of footnote ‘b’ with adjacent planners

III. Instances for which Approval of Interruptions of Firm Demand under Footnote ‘b’ is
Required
Approval of the use of Firm Demand interruption under footnote ‘b’ by the applicable regulatory
authority or governing body responsible for retail electric service issues is required 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 Firm Demand interruptions under footnote ‘b’
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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW.
Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an element of
a Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed x MW.
When approval for the use of a footnote ‘b’ Firm Demand interruption is necessary under
items III.1 or III.2 above, the Planning Coordinator or Transmission Planner must submit
the information outlined in items II.1 through II.8 above to the Regional Entity. Within 45
days of receipt of this information, the Regional Entity must review each proposed use of
Firm Demand interruption under footnote ‘b’ to verify that there are no Adverse Reliability
Impacts including any potential cumulative effect within the Regional Entity’s footprint. If
the Regional Entity states that an Adverse Reliability Impact will result due to the
requested Firm Demand interruption, then the requesting entity may appeal the decision to

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the ERO. Regional Entity determinations of Adverse Reliability Impacts are to be
evaluated by the Regional Entity through a published methodology approved by the ERO.

Draft 61:July 31, 2012

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S ta n d a rd TP L-002-1c b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

Draft 61:July 31, 2012

Page 11 of 15

S ta n d a rd TP L-002-1c b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Draft 61:July 31, 2012

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S ta n d a rd TP L-002-1c b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Draft 61:July 31, 2012

Page 13 of 15

S ta n d a rd TP L-002-1c b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

Draft 61:July 31, 2012

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S ta n d a rd TP L-002-1c b — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Draft 61:July 31, 2012

Page 15 of 15

Project 2010-11
Revision of TPL-002 footnote ‘b’ and TPL-001
footnote 12
Unofficial Comment Form
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by August 29, 2012.
If you have questions please contact Ed Dobrowolski at [email protected] or by telephone at
609-947-3673.
The project web page is located here:
http://www.nerc.com/filez/standards/Project2010-11_TPL_Table-1_Order.html
Background Information
This posting is soliciting formal comment.
FERC Order No. 762 issued April 19, 2012 remanded TPL-002-0b as vague, unenforceable and not
responsive to the previous Commission directives on this matter. The Standards Committee directed
the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of Orders
No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL-001-2
in order to prevent the remand of TPL-001-2.
The SDT adopted a philosophy of minimal changes to the actual footnote itself. This was done to
minimize confusion as to what was changed, for ease of reading and following the footnote, and for
formatting within the actual standards documents. This philosophy resulted in the development of an
attachment to the footnote where the actual changes in response to the Commission Orders are
contained. It should be noted that attachments to standards are part and parcel of the standard itself
and thus are binding to applicable entities.
A draft data request to collect data to assist the SDT in its work was posted for an abbreviated
comment period in accordance with Section 1600 of the NERC Rules of Procedure, through July 9,
2012. The draft data request will be revised as appropriate to reflect industry comments and then
issued for formal response. The timing of the formal data request response will allow for the data to
be evaluated by the SDT in the same timeframe as the responses to this posting.

YYYY-##.# - Project Name Revision of TPL-002 footnote ‘b’ and TPL-001 footnote
12 Project YYYY-##.# - Project Name

Project

The SDT has proposed three thresholds within the proposed footnote revision in Section III of
Attachment 1 in order to address the Order.
• The last sentence in the body of the footnote is to allow for the placement of a maximum
capacity limit to the amount of Firm Demand that be be dropped under footnote ‘b’. The value
is currently shown as ‘x’ MW. The SDT will fill in the value after the above mentioned data
request is complete and will submit the value for industry comment and approval in the next
posting. However, industry comments on the proposed maximum capacity issue can be
submitted now in response to question 1.
• The 300 kV threshold in Section III is derived from the EHV value approved by the industry
through the Standards Development Process, approved by the NERC Board of Trustees, and
favorably received by the Commission in the TPL-001-2 filing.
• The 25 MW threshold in Section III is duplicative of the registration limit for generation in the
ERO Statement of Compliance Registry Criteria. It is submitted for comment at this time but
will not be finalized until after the above mentioned data request is complete and the final
value will be submitted for industry comment and approval in the next posting.
There have been no changes to the Implementation Plan originally filed with the standards.
You do not have to answer all questions. Enter All Comments in Simple Text Format. Bullets, numbers,
and special formatting will not be retained.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.
1. Do you agree with the description and components of the the Stakeholder Process in the body of the

footnote including the maximum capacity threshold (currently shown as ‘x’ MW but the SDT will fill in
the value after the data request is complete and will submit the value for industry comment and
approval in the next posting)? If you do not support these changes or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your
comments. For the maximum capacity item, please supply any technical rationale for your comment
along with limiting conditions and any current criteria in use at your entity.
Yes
No
Comments:

Unofficial Comment Form: Project 2010-11

2

YYYY-##.# - Project Name Revision of TPL-002 footnote ‘b’ and TPL-001 footnote
12 Project YYYY-##.# - Project Name

Project

2. Do you agree with the description and components of the the Stakeholder Process in Section I of

Attachment I? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
3. Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of
Attachment I? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
4. Do you agree with the Instances for which Approval of Interruptions is required in Section III of
Attachment I? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
5. If you have any other comments on this Standard that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form: Project 2010-11

3

Item 5cii

Standard Authorization Request Form
Request Date

Revision of TPL-002 footnote ‘b’ and TPL-001 footnote 12

SAR Requester Information

SAR Type (Check a box for each one
that applies.)

Individual, Group, or Committee Name
Standards Committee
Primary Contact (if Group or Committee) Allen
Mosher
Company or Group Name

APPA

E-mail [email protected]

Telephone

(202) 467-2944

New Standard
X

Revision to existing Standard
Withdrawal of existing Standard
Project Identified in Reliability
Standards Development Plan
(Project Number and Name:

)

Modification to NERC Glossary term
or addition of new term

Standards Authorization Request Form

Brief Description of Proposed Standard Modifications/Actions
The drafting team must provide clarity on TPL-002-0, Table 1 - footnote ‘b’ and TPL-001-2
Table 1 footnote 12, regarding the planned or controlled interruption of electric supply
where a single contingency occurs on a transmission system. The drafting team must
quickly respond to the directives in Order No. 762 in order to preserve their ability toto
address planned to load shed load under limited circumstances for certain contingencies.
Need
On April 19, 2012, FERC issued Order No. 762 remanding TPL-002-2b because FERC
determined that footnote b to Table 1 of that Reliability Standard was vague, unenforceable,
and not responsive to previous directives. Therefore FERC found TPL-002-2b to be unjust,
unreasonable, unduly discriminatory or preferential, and not in the public interest. In a
related matter, FERC proposed to remand TPL-001-2 because NERC incorporated footnote b
into the new TPL-001-2 reliability standard.
NERC has been directed to revise footnote b in accordance with the directives of Order Nos.
762 and 693. This project will also revise footnote 12 to TPL-001-2 in order to prevent the
remand of TPL-001-2.
This provision will allow for entities to plan to shed load under very limited circumstances so
long as there is no adverse reliability impact to the BES.
Goals (Describe what must be accomplished in order to meet the above need. This section
would become the Requirements in a Reliability Standard.)
NERC must develop a process that will not adversely impact BES reliability and that satisfies
the directives of Order No. 762 by clearly delineating when entities may plan for load
shedding following a single contingency.
Objectives and/or Potential Future Metrics
The drafting team must either develop a blend of quantitative and qualitative methodologies
or a specific “customer consent” process that will allow for planning to shed load following a
single contingency. The drafting team must consider the guidance provided by the
Commission in Order 762, including but not limited to:
• Form OE-417 or the Registry Criteria are not, by themselves, beneficial to use to
devise criteria (see paragraph 49 of Order 762). .
• Setting a quantitative and qualitative threshold in developing a limited exception for
planned interruption of Firm Demand may be a workable solution (see paragraph 54
of Order 762).
• A customer should have notice and understanding that the transmission planner
plans to curtail certain Firm Demand in the event of a single contingency indentified
in the system modeling under NERC’s Transmission Planning requirements (see
paragraph 65 of Order 762).
• If there is a threshold component to the revised footnote, the rational for the
threshold should be supported and show that instability, uncontrolled separation, or
cascading failures of the system will not occur as a result of planning to shed Firm
Demand up to the threshold (see paragraph 67 of Order 762).
• If there is an individual exception option, the applicable entities should be required to
find that there is no adverse impact to the Bulk-Power System from the exception
and that it is considered in wide-area coordination and operations (see paragraph 67
of Order 762).
• Any exception should be subject to further review by the Regional Entity or NERC
(see paragraph 67 of Order 762).
Detailed Description The drafting team must provide clarity on TPL-002-0, Table 1 SAR–2

Standards Authorization Request Form

footnote ‘b’ and TPL-001-2 Table 1 footnote 12, regarding the planned or controlled
interruption of electric supply where a single contingency occurs on a transmission system.
The drafting team must quickly respond to the directives in Order No. 762 in order to to
address planned load shed under preserve their ability to plan to shed load under limited
circumstances for certain contingencies.
NERC has been directed to revise footnote b in accordance with the directives of Order Nos.
762 and 693. This project will also revise footnote 12 to TPL-001-2 in order to prevent the
remand of TPL-001-2.
This provision will allow for entities to plan to shed load under very limited circumstances so
long as there is no adverse reliability impact to the BES.
OPTIONAL: Technical Analysis Performed to Support Justification
NERC will be conducting a mandatory Data Request to identify the specific instances of any
planned interruptions of Firm Demand under footnote ‘b’ and how frequently the provision
has been used in parallel with this SAR. The drafting team should evaluate and consider the
results of the data request in conjunction with drafting the revised Footnote b.

Reliability Functions
The Standard(s) May Apply to the Following Functions (Check box for each one that
applies.)

X

X

Regional
Entity

Conducts the regional activities related to planning and
operations, and coordinates activities of Responsible Entities to
secure the reliability of the Bulk Electric System within the region
and adjacent regions.

Reliability
Coordinator

Responsible for the real-time operating reliability of its Reliability
Coordinator Area in coordination with its neighboring Reliability
Coordinator’s wide area view.

Balancing
Authority

Integrates resource plans ahead of time, and maintains loadinterchange-resource balance within a Balancing Authority Area
and supports Interconnection frequency in real time.

Interchange
Authority

Ensures communication of interchange transactions for reliability
evaluation purposes and coordinates implementation of valid and
balanced interchange schedules between Balancing Authority
Areas.

Planning
Coordinator

Assesses the longer-term reliability of its Planning Coordinator
Area.

Resource
Planner

Develops a >one year plan for the resource adequacy of its
specific loads within a Planning Coordinator area.

Transmission
Planner

Develops a >one year plan for the reliability of the
interconnected Bulk Electric System within its portion of the
Planning Coordinator area.

Transmission
Service
Provider

Administers the transmission tariff and provides transmission
services under applicable transmission service agreements (e.g.,
the pro forma tariff).

Transmission

Owns and maintains transmission facilities.
SAR–3

Standards Authorization Request Form

Owner
Transmission
Operator

Ensures the real-time operating reliability of the transmission
assets within a Transmission Operator Area.

Distribution
Provider

Delivers electrical energy to the End-use customer.

Generator
Owner

Owns and maintains generation facilities.

Generator
Operator

Operates generation unit(s) to provide real and reactive power.

PurchasingSelling Entity

Purchases or sells energy, capacity, and necessary reliabilityrelated services as required.

Market
Operator

Interface point for reliability functions with commercial functions.

LoadServing
Entity

Secures energy and transmission service (and reliability-related
services) to serve the End-use Customer.

SAR–4

Standards Authorization Request Form

Reliability and Market Interface Principles
Applicable Reliability Principles (Check box for all that apply.)
X

1. Interconnected bulk power systems shall be planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions as defined in the
NERC Standards.
2. The frequency and voltage of interconnected bulk power systems shall be controlled
within defined limits through the balancing of real and reactive power supply and
demand.
3. Information necessary for the planning and operation of interconnected bulk power
systems shall be made available to those entities responsible for planning and
operating the systems reliably.
4. Plans for emergency operation and system restoration of interconnected bulk power
systems shall be developed, coordinated, maintained and implemented.
5. Facilities for communication, monitoring and control shall be provided, used and
maintained for the reliability of interconnected bulk power systems.
6. Personnel responsible for planning and operating interconnected bulk power systems
shall be trained, qualified, and have the responsibility and authority to implement
actions.
7. The security of the interconnected bulk power systems shall be assessed, monitored
and maintained on a wide area basis.
8. Bulk power systems shall be protected from malicious physical or cyber attacks.

Does the proposed Standard(s) comply with all of the following Market Interface
Principles? (Select ‘yes’ or ‘no’ from the drop-down box.)
1. A reliability standard shall not give any market participant an unfair competitive
advantage. Yes
2. A reliability standard shall neither mandate nor prohibit any specific market structure. Yes
3. A reliability standard shall not preclude market solutions to achieving compliance with that
standard. Yes
4. A reliability standard shall not require the public disclosure of commercially sensitive
information. All market participants shall have equal opportunity to access commercially
non-sensitive information that is required for compliance with reliability standards. Yes

SAR–5

Standards Authorization Request Form

Related Standards
Standard No.

Explanation

TPL-001-0.1

System Performance Under Normal (No Contingency) Conditions (Category
A)

TPL-002-0b

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

TPL-003-0a

System Performance Following Loss of Two or More Bulk Electric System
Elements (Category C)

TPL-004-0

System Performance Following Extreme Events Resulting in the Loss of
Two or More Bulk Electric System Elements (Category D)

Related Projects
Project ID and Title

Explanation

Regional Variances
Region

Explanation

ERCOT
FRCC
MRO
NPCC
SERC
RFC
SPP
WECC

SAR–6

20120419-3103 FERC PDF (Unofficial) 04/19/2012

139 FERC ¶ 61,060
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 40
[Docket No. RM11-18-000; Order No. 762]
Transmission Planning Reliability Standards
(Issued April 19, 2012)
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final Rule.
SUMMARY: Under section 215 of the Federal Power Act, the Federal Energy
Regulatory Commission remands proposed Transmission Planning (TPL) Reliability
Standard TPL-002-0b, submitted by the North American Electric Reliability Corporation
(NERC), the Commission-certified Electric Reliability Organization. The proposed
Reliability Standard includes a provision that allows for planned load shed in a single
contingency provided that the plan is documented and alternatives are considered and
vetted in an open and transparent process. The Commission finds that this provision is
vague, unenforceable and not responsive to the previous Commission directives on this
matter. Accordingly, the Final Rule remands NERC’s proposal as unjust, unreasonable,
unduly discriminatory or preferential, and not in the public interest.
DATES: This rule will become effective [Insert date 60 days after publication in the
FEDERAL REGISTER].
ADDRESSES: You may submit comments, identified by docket number by any of the
following methods:

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

-2-

 Agency Web Site: http://www.ferc.gov. Documents created electronically using
word processing software should be filed in native applications or print-to-PDF
format and not in a scanned format.
 Mail/Hand Delivery: Commenters unable to file comments electronically must
mail or hand deliver comments to: Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First Street, NE, Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT:
Eugene Blick (Technical Information)
Office of Electric Reliability
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Telephone: (202) 502-8066
[email protected]
Robert T. Stroh (Legal Information)
Office of the General Counsel
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Telephone: (202) 502-8473
[email protected]
SUPPLEMENTARY INFORMATION:

20120419-3103 FERC PDF (Unofficial) 04/19/2012

139 FERC ¶ 61,060
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: Jon Wellinghoff, Chairman;
Philip D. Moeller, John R. Norris,
and Cheryl A. LaFleur.
Transmission Planning Reliability Standards

Docket No. RM11-18-000

Order No. 762
FINAL RULE
(Issued April 19, 2012)
1.

Under section 215(d) of the Federal Power Act,1 the Commission remands

proposed Transmission Planning (TPL) Reliability Standard TPL-002-0b, submitted by
the North American Electric Reliability Corporation (NERC), the Commission-certified
Electric Reliability Organization. The proposed Reliability Standard includes a provision
that allows for planned load shed in a single contingency provided that the plan is
documented and alternatives are considered and vetted in an open and transparent
process.2 The Commission finds that this provision is vague, unenforceable and not
responsive to the previous Commission directives on this matter. Accordingly, the Final

1

16 U.S.C. § 824o(d)(4) (2006).

2

NERC filed a petition seeking approval of Table 1, footnote ‘b’ of four
Reliability Standards: Transmission Planning: TPL-001-1– System Performance Under
Normal (No Contingency) Conditions (Category A), TPL-002-1b – System Performance
Following Loss of a Single Bulk Electric System Element (Category B), TPL-003-1a –
System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C), and TPL-004-1– System Performance Following Extreme Events Resulting
(continued…)

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Rule remands NERC’s proposal as unjust, unreasonable, unduly discriminatory or
preferential, and not in the public interest. We require NERC to utilize its Expedited
Reliability Standards Development Process to develop timely modifications to TPL-0020b, Table 1 footnote ‘b’ in response to our remand.3
I.

Background

2.

Section 215 of the FPA requires a Commission-certified Electric Reliability

Organization (ERO) to develop mandatory and enforceable Reliability Standards, which
are subject to Commission review and approval. Approved Reliability Standards are
enforced by the ERO, subject to Commission oversight, or by the Commission
independently. On March 16, 2007, the Commission issued Order No. 693, approving 83
of the 107 Reliability Standards filed by NERC, including Reliability Standard TPL-0020.4 In addition, pursuant to section 215(d)(5) of the FPA,5 the Commission directed

in the Loss of Two or More Bulk Electric System Elements (Category D). While
footnote ‘b’ appears in all four of the above referenced TPL Reliability Standards, its
relevance and practical applicability is limited to TPL-002-0a.
3

NERC Rules of Procedure, Appendix 3A, Standard Processes Manual at 34
(effective January 31, 2012).
4

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693,
FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007).
5

16 U.S.C. § 824o(d)(5)(2006).

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NERC to develop modifications to 56 of the 83 approved Reliability Standards, including
footnote ‘b’ of Reliability Standard TPL-002-0.6
A.
3.

Transmission Planning (TPL) Reliability Standards

Currently-effective Reliability Standard TPL-002-0b addresses Bulk-Power System

planning and related transmission system performance for single element contingency
conditions. Requirement R1 of TPL-002-0b requires that each planning authority and
transmission planner “demonstrate through a valid assessment that its portion of the
interconnected transmission system is planned such that the network can be operated to
supply projected customer demands and projected firm transmission services, at all
demand levels over the range of forecast system demands, under the contingency
conditions as defined in Category B of Table I.”7 Table I identifies different categories of
contingencies and allowable system impacts in the planning process. With regard to
system impacts, Table I further provides that a Category B (single) contingency must not
result in cascading outages, loss of demand or curtailed firm transfers, system instability
or exceeded voltage or thermal limits. With regard to loss of demand, current footnote
‘b’ of Table 1 states:
Planned or controlled interruption of electric supply to radial customers or
some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems.
6

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1797.

7

Reliability Standard TPL-002-0a, Requirement R1.

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To prepare for the next contingency, system adjustments are permitted,
including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers.
B.
4.

Order No. 693 Directive

In Order No. 693, the Commission stated that it believes that the transmission

planning Reliability Standard should not allow an entity to plan for the loss of nonconsequential firm load in the event of a single contingency.8 The Commission directed
the ERO to develop certain modifications, including a clarification of Table 1, footnote
‘b.’
5.

In a subsequent clarifying order, the Commission stated that it believed that a

regional difference, or a case-specific exception process that can be technically justified,
to plan for the loss of firm service would be acceptable in limited circumstances.9
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.”10

8

See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1794.

9

Mandatory Reliability Standards for the Bulk Power System, 131 FERC
¶ 61,231, at P 21 (2010) (June 2010 Order).
10

Id.

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C.
6.

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NERC Petition

On March 31, 2011, NERC filed a petition seeking approval of its proposal to

revise and clarify footnote ‘b’ “in regard to load loss following a single contingency.”11
NERC stated that it did not eliminate the ability of an entity to plan for the loss of nonconsequential load in the event of a single contingency but drafted a footnote that,
according to NERC, “meets the Commission’s directive while simultaneously meeting
the needs of industry and respecting jurisdictional bounds.”12 NERC stated that its
proposed footnote ‘b’ establishes the requirements for the limited circumstances when
and how an entity can plan to interrupt Firm Demand for Category B contingencies.
According to NERC, the provision allows for planned interruption of Firm Demand when
“subject to review in an open and transparent stakeholder process.” 13 NERC’s proposed
footnote ‘b’ states:
An objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved
through the appropriate redispatch 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 redispatch does not result in the shedding of any Firm Demand. It is recognized that
Firm Demand will be interrupted if it is: (1) directly served by the Elements
removed from service as a result of the Contingency, or (2) Interruptible Demand
or Demand-Side Management Load. Furthermore, in limited circumstances Firm
Demand may need to be interrupted to address BES performance requirements.
11

NERC Petition at 10.

12

Id.

13

Id.

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When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to
circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in
an open and transparent stakeholder process that includes addressing stakeholder
comments.
7.

NERC supplemented the filing on June 7, 2011, in response to a Commission

deficiency letter. NERC explained that “the approach proposed in footnote ‘b’ is equally
efficient because many of the stakeholder processes that will be used in footnote ‘b’
planning decisions are already in place, as implemented by FERC in Order No. 890 and
in state regulatory jurisdictions.”14 NERC also pointed to state public utility commission
processes or processes existing in local jurisdictions that address transmission planning
issues that could serve to provide a case-specific review of the planned interruption of
Firm Demand. According to NERC, such processes would more likely engage the
appropriate local-level decision-makers and policy-makers.
8.

With respect to review and oversight by NERC and the Regional Entities, NERC

submitted that an ERO-specific process would place the ERO in the position of managing
and actively participating in a planning process, which conflicts with its role as the
compliance monitor and enforcement authority. NERC also stated that neither the ERO
nor the Regional Entities will review decisions regarding planned interruptions. Their
role will be limited to reviewing whether the registered entity participated in a
stakeholder process when planning to interrupt Firm Demand. NERC explained that
14

NERC Data Response at 4.

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Regional Entities will have oversight after-the-fact by auditing the entity’s
implementation of footnote ‘b’ to determine if the entity planned on interrupting Firm
Demand and whether the decision by the entity to rely on planned interruption of Firm
Demand was vetted through the stakeholder process and qualified as one of the situations
identified in footnote ‘b.’
9.

Furthermore, NERC stated that an objective of the planning process should be to

minimize the likelihood and magnitude of planned Firm Demand interruptions. NERC
contended that, due to the wide variety of system configurations and regulatory compacts,
it is not feasible for the ERO to develop a one-size-fits-all criterion for limiting the
planned firm load interruptions for Category B events. According to NERC, the
standards drafting team evaluated setting a certain magnitude of planned interruption of
Firm Demand, but there was no analytical data to support a single value, and it would be
viewed as arbitrary.
D.
10.

Notice of Proposed Rulemaking

On October 20, 2011, the Commission issued a Notice of Proposed Rulemaking

(NOPR15) proposing to remand NERC’s proposal to modify footnote ‘b.’ In the NOPR,
the Commission stated that it believed that NERC’s proposal does not meet the directives
in Order No. 693 and the June 2010 Order and does not clarify or define the
circumstances in which an entity can plan to interrupt Firm Demand for a single
15

Transmission Planning Reliability Standards, Notice of Proposed Rulemaking,
76 FR 66229 (Oct. 20, 2011), FERC Stats. & Regs. ¶ 32,683 (2011).

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contingency. The Commission expressed concern that the procedural and substantive
parameters of NERC’s proposed stakeholder process are too undefined to provide
assurances that the process will be effective in determining when it is appropriate to plan
for interrupting Firm Demand, does not contain NERC-defined criteria on circumstances
to determine when an exception for planned interruption of Firm Demand is permissible,
and could result in inconsistent results in implementation. The NOPR stated that the
proposed footnote effectively turns the processes into a reliability standards development
process outside of NERC’s existing procedures. Furthermore, the NOPR stated that
regardless of the process used, the result could lead to inconsistent reliability
requirements within and across reliability regions. While the Commission recognized
that some variation among regions or entities is reasonable, there are no technical or other
criteria to determine whether varied results are arbitrary or based on meaningful
distinctions.
11.

The Commission proposed to provide further guidance on acceptable approaches to

footnote ‘b’ and sought comment on certain options for revising footnote ‘b’, as well as
other potential options to solve the concerns outlined in the NOPR. In response to the
NOPR, comments were filed by seventeen interested parties.16

16

NERC, The Edison Electric Institute (EEI), American Public Power Association
(APPA), National Association of Regulatory Utility Commissioners (NARUC), ITC
Holdings Corp. (ITC), Manitoba Hydro, California Department of Water Resources State
Water Project (California SWP) Hydro One Networks, Inc and the Ontario Independent
Electricity System Operator (Hydro One and IESO), Duke Energy Corporation (Duke),
New York State Public Service Commission (NYPSC), Bonneville Power Administration
(continued…)

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II.

Discussion

12.

For the reasons discussed below, the Commission concludes that NERC’s

proposed TPL-002-0b does not meet the Commission’s Order No. 693 directives, nor is it
an equally effective and efficient alternative. Further, the Commission finds that the
proposal is vague, potentially unenforceable and may lack safeguards to produce
consistent results. On this basis, the Commission remands the proposal to NERC as
unjust, unreasonable, unduly discriminatory or preferential and not in the public interest.
Below, the Commission also provides guidance on acceptable approaches to footnote ‘b.’
13.

The Commission adopts the proposed NOPR finding that the footnote ‘b’ process

lacks adequate parameters. The Reliability Standard requires that, when planning to
interrupt Firm Demand, the Firm Demand interruption must be “subject to review in an
open and transparent stakeholder process that includes addressing stakeholder
comments.”17 Without meaningful substantive parameters governing the stakeholder
process, the enforceability of this obligation by NERC and the Regional Entities would
be limited to a review to ensure only that a stakeholder process occurred. As NERC
explained, Regional Entities’ involvement is limited to after-the-fact oversight by

(BPA), Kansas City Power & Light Company and KCP&L Greater Missouri Operations
Company (KCPL), Midwest Independent System Operator, Inc. (MISO), Public Utility
District No. 1 of Snohomish County, Washington, (Snohomish), Transmission Access
Policy Study Group (TAPS), Powerex Corp. (Powerex), and Florida Reliability
Coordinating Council (FRCC).
17

NERC Petition at 10.

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auditing the entity’s implementation of footnote ‘b’ to determine if the entity planned on
interrupting Firm Demand and whether the decision by the entity to rely on planned
interruption of Firm Demand was vetted through the stakeholder process and qualified as
one of the situations identified in footnote ‘b.’18
14.

Further, the NERC proposal leaves undefined the circumstances in which it is

allowable to plan for Firm Demand to be interrupted in response to a Category B
contingency. The Commission believes that proposed footnote ‘b’ could be used as a
means to override the reliability objective and system performance requirements of the
TPL Reliability Standard without any technical or other criteria specified to determine
when planning to interrupt Firm Demand would be allowable, and without violating any
of the requirements of the TPL Reliability Standard. The TPL Reliability Standard
requires that a planner demonstrate through a valid assessment that the transmission
system is planned and can be operated to supply projected Firm Demand at all demand
levels over a range of forecasted system demands.19 In addition, a planner must consider
all single contingencies under Table 1, Category B and demonstrate system
performance.20 For single contingency events where system performance is not met, a
planner must provide a written summary of its plans to achieve system performance

18

NERC Data Response at 7-9.

19

Reliability Standard TPL-002-0b, Requirement R1.

20

Reliability Standard TPL-002-0b, Requirement R1.3.7.

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including implementation schedules, in service dates of facilities and implementation
lead times.21
15.

However, if system performance is not met for any single contingency event(s)

under NERC’s proposed footnote ‘b,’ a planner could plan to interrupt some portion of
Firm Demand to meet system performance requirements thereby overriding the
performance requirements of the TPL Reliability Standard. For example, if a planner
determines during its annual assessment that for a single bulk-power system transformer
contingency other bulk-power system elements would exceed their thermal ratings, a
planner would have authority under the standard to plan to interrupt Firm Demand to
relieve the exceeded thermal ratings of the bulk-power system elements rather than
planning the system to withstand such a single contingency and avoid shedding firm load
as the performance requirements of the TPL Reliability Standard require. Therefore,
without articulating some bounds on the use of the planned shedding of Firm Demand,
there could be instances of multiple exceptions that could affect the robustness of the
system. Further, contrary to commenters contentions, NERC’s proposal, for example,
has no provision to evaluate this cumulative effect of the individual decisions to shed
firm.22

21

Reliability Standard TPL-002-0b, Requirement R2.

22

BPA Comments at 5 (“The reasons for interrupting Firm Demand would be
documented in studies and demonstrate that there would be no adverse impact to the
BPS”); FRCC Comments at 3 (“Indeed, the transmission planning entity is responsible as
part of the system assessment process under the TPL standards to test remedies to ensure
(continued…)

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16.

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The Commission disagrees with commenters that NERC’s proposed footnote ‘b’

will have no adverse impact on reliable planning of the bulk-power system because
planning to shed Firm Demand is intended to ensure that single contingency events do
not result in adverse impacts and intended to preserve bulk-power system reliability.23
Table 1 of the TPL Reliability Standard identifies the system performance requirements
or “System Limits or Impacts” that a planner must apply during its assessment of
Category B, single contingency events.24 Except in limited circumstances, if a planner
determines that it must plan to interrupt Firm Demand so that it does not violate the Table
1 system performance requirements, a planner should not apply footnote ‘b’ as a
mitigation plan to plan to operate reliably.

The Commission therefore is concerned that

NERC’s proposal provides authority to adjust the TPL Reliability Standard and its system

that they address the problems being caused and do not cause additional problems.”); and
Hydro One Comments at 5 (“Loss of load is under the purview of the regulatory authority
and not NERC, unless it has an adverse impact on the BES which is already taken into
consideration by the TPL standards… In all cases, steps are taken in planning, design and
operations of the system to ensure that Firm Demand shedding would not adversely
impact the BES…”).
23

See, e.g., NERC Comments at 11, TAPS Comments at 10, APPA Comments at

6.
24

Reliability Standard TPL-002-0b, Table 1, Transmission System Standards –
Normal and Emergency Conditions. Table 1 identifies the system performance
requirements or “System Limits or Impacts” which are as follows: “System Stable and
both Thermal and Voltage Limits within Applicable Rating”, “Loss of Demand or
Curtailed Firm Transfers” and “Cascading Outages.”

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performance requirements for each single contingency event that does not meet the
system performance requirements of Table 1.
17.

Further, NERC has not provided technically sound means of determining

situations in which planning to interrupt Firm Demand would be allowable. While
NERC expects that such determinations will be made in a stakeholder process, this
provides no assurance that such a process will use technically sound means of approving
or denying exceptions. The Commission concludes that the multiple stakeholder
processes across the country engaging in such determinations could lead to inconsistent
and arbitrary exceptions including, potentially, allowing entities to plan to interrupt any
amount of Firm Demand in any location and at any voltage level.
18.

While the Commission recognizes that some variation among regions or entities is

reasonable given varying grid topography and other considerations, there are no technical
or other criteria to determine whether varied results are arbitrary or based on meaningful
distinctions. The Commission, thus, concludes that NERC’s proposal lacks safeguards to
ensure against inconsistent results and arbitrary determinations to allow for the planned
interruption of Firm Demand.
19.

A remand gives NERC and industry flexibility to develop an approach that would

address the issues identified by the Commission with the proposed footnote ‘b’
stakeholder process including, as discussed below, definition of the process and criteria
or guidelines for the process.
20.

The Commission believes that, on remand, both NERC and the Commission will

benefit from a more complete record regarding the electric industry’s reliance on planned

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Firm Demand interruptions. In response to the Commission’s request to explain and
quantify the extent to which Firm Demand is planned to be interrupted pursuant to
currently-effective footnote ‘b,’ NERC explained:
NERC and the Regional Entities have not collected statistics or
preformed a survey concerning the prospective implementation of
Footnote b under TPL-002-0a. During the drafting team’s
deliberations concerning TPL-001-2 and TPL-002-0a Footnote b,
including the NERC Technical Conference on Footnote b, the
informal assessments demonstrated that the use of Footnote b would
not be widespread.25
Likewise, several commenters state that the interruption of Firm Demand is rarely
needed, but provide no support for this conclusion.26 For example, EEI asks the
Commission to “recognize” that “…the actions taken as outcomes of the planning review
process, are likely to identify few/isolated circumstances in which these [footnote b]
provisions would be invoked….”27

However, the Commission believes that more

specific information regarding the specific circumstances and frequency with which Firm
Demand is planned to be interrupted will assist both NERC in developing, and the
Commission in reviewing, appropriate revisions to footnote ‘b” on remand. Therefore,
pursuant to section 39.2(d) of the Commission’s regulations,28 we direct NERC to
identify the specific instances of any planned interruptions of Firm Demand under
25

NERC Data Response at 10.

26

See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA Comments.

27

EEI Comments at 2.

28

18 U.S.C. § 39.2(d).

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footnote ‘b’ and how frequently the provision has been used. We direct 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.29 NERC shall submit
this information to the Commission with NERC’s footnote ‘b’ filing that addresses the
concerns in this Final Rule.
21.

We urge NERC to develop in a timely manner an appropriate modification that is

responsive to the Commission’s directives in Order No. 693 and our concerns set forth in
this Final Rule. In that regard, we require NERC to deploy its Expedited Reliability
Standards Development Process to quickly respond to the remand. As the Commission
noted in previous orders, the use of planned or controlled load interruption is a
fundamental reliability issue and, certainty regarding the loss of non-consequential load
for a single contingency event is warranted.30 Thus, using the Expedited Standards
Development Process will more rapidly bring needed certainty to this fundamental
reliability issue.
22.

Below we discuss three concerns: (a) jurisdictional issues, (b) lack of technical

criteria, and (c) the stakeholder process. The Commission also provides guidance on
other acceptable approaches.

29
30

NERC Rules of Procedure, Section 1601 (effective January 31, 2012).

North American Electric Reliability Corp., 130 FERC ¶ 61,200 (2010) (March
2010 Order); North American Electric Reliability Corp., 131 FERC ¶ 61,231 (2010)
(June 2010 Order).

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A.
23.

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Jurisdictional Issues

A number of commenters express concern that the Commission is reaching beyond

its FPA section 215 jurisdiction.31 Commenters assert that the Commission options
exceed its jurisdiction involving acceptable levels and types of service. Commenters
seek assurance that the Commission’s proposal does not infringe on matters reserved to
the States and instead “only prescribe acceptable load shedding as it pertains to wholesale
customers that are in a position to select interruptible or conditional firm transmission
service.”32 NARUC states that “any NERC standard for shedding distribution level load
must be guided by States and that a demonstration that interruption of the load will not
cause instability, uncontrolled separation, or cascading failures on the bulk system is
appropriate for a NERC standard.” 33 NARUC adds that specifications of what retail load
and what levels of retail load can be interrupted is a State determination that is not
reviewable by the Commission. TAPS agrees with NERC that issues pertaining to
whether it is permissible to plan to interrupt firm load involves conflicts among federal,
provincial, state, and local governing bodies.34
24.

The Commission disagrees that it is infringing on State Commissions or

overstepping jurisdictional bounds. In this Final Rule, the Commission remands NERC’s
31

See, e.g., Comments of NERC, NARUC, APPA and TAPS.

32

NYPSC Comments at 5.

33

NARUC Comments at 3-4.

34

TAPS Comments at 9.

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proposed footnote ‘b’ as an inadequate mechanism to address planned curtailment of firm
demand and not responsive to the Commission’s directives in Order No. 693 regarding
this matter. The Commission is not directing that NERC develop a specific solution or
approach on remand. Thus, our remand of the NERC proposed modification to TPL-0020b, Table 1, footnote ‘b’ is fully within the Commission’s authority pursuant to section
215(d)(4) to remand to the ERO for further consideration a modification to a proposed
reliability standard that the Commission disapproves in whole or in part. Moreover,
FPA section 215 gives the Commission jurisdiction over mandatory Reliability Standards
to ensure reliability of the Bulk-Power System.35 Consistent with its statutory authority,
the Commission’s interest and focus in this proceeding is on the planned interruption of
Firm Demand on the Bulk-Power System. The Commission views this matter in the
context of Reliability Standard TPL-002-0b, which requires that in planning the system to
withstand the loss of a single Bulk-Power System element, Bulk-Power System
performance criteria must be met. If it is not met, a corrective action plan is required to
address the Bulk-Power System performance criteria violation. Contingencies studied
pursuant to Reliability Standard TPL-002-0b pertinent to Bulk-Power System facilities
are subject to Commission jurisdiction under FPA section 215. In sum, the performance
of the Bulk-Power System under the TPL-002-0b Reliability Standard is within the
Commission’s jurisdiction.

35

16 U.S.C. § 824o(b)(1).

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B.

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Lack of Technical Criteria
NOPR Proposal

25.

In the NOPR, the Commission proposed to remand NERC’s proposal to modify

Reliability Standard TPL-002-0b, Table 1, footnote ‘b.’ The Commission stated that it
believed that NERC’s proposal does not meet the directives in Order No. 693 and the
June 2010 Order and does not clarify or define the circumstances in which an entity can
plan to interrupt Firm Demand for a single contingency.36 In the NOPR the Commission
expressed concern that NERC’s proposed footnote ‘b’ lacks parameters. Without any
substantive parameters governing the stakeholder process, the enforceability of this
obligation by NERC and the Regional Entities would be limited to a review to ensure
only that a stakeholder process occurred. The Commission noted that NERC appears to
confirm this concern, as NERC explained that Regional Entities’ involvement is limited
to after-the-fact oversight by auditing the entity’s implementation of footnote ‘b’ to
determine if the planned interruption of Firm Demand was vetted through the stakeholder
process.37
26.

Further, in the NOPR the Commission stated that since the proposed footnote ‘b’

contains no constraints, it could allow an entity to plan to interrupt any amount of
planned Firm Demand, in any location or at any voltage level as needed for any single
contingency, provided that it is documented and subjected to a stakeholder process. The
36

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 11.

37

Id. P 12.

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Commission found this result remains contrary to the underlying Reliability Standard and
prior Commission orders.38 The Commission requested comment on this specific
concern of the lack of technical criteria or parameters.
Comments
27.

Some commenters agree with the Commission that there is lack of technical criteria

to determine planned interruption of Firm Demand. For example, California SWP states
that Reliability Standards “should ensure transparent criteria based on technical merits
and not software limitations derived from a desire to mask [locational marginal pricing]
price signals with socialized pricing or on status quo practices.”39 ITC believes that there
is a need for defined parameters that will guide the review of exceptions and that will
prevent planned interruptions from becoming commonplace.40 Manitoba Hydro states
that the characteristics of openness and transparency are indicators of a nondiscriminatory planning process; however, these characteristics do not ensure that certain
reliability criteria of the planned facilities will be met.41
28.

Other commenters disagree with the Commission’s concern that there is a lack of

criteria to determine planned interruption of Firm Demand. NERC states that it does not
believe that an exceptions process that provides defined criteria, with some allowances,
38

Id.

39

California SWP Comments at 4.

40

ITC Comments at 2.

41

Manitoba Hydro Comments at 6.

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could be crafted that would respect pre-existing decision making processes that occur at
state and local jurisdictions. NERC argues that the decision to interrupt local load is
essentially an economic decision – a quality of service issue, not a reliability issue.42
29.

MISO disagrees that additional language would reduce the potential for

inconsistent results and points out that registered entities already have many established
requirements that govern the transmission planning processes.43 MISO believes that if
the Commission determines that criteria are needed, such criteria should be determined
by the stakeholders in the regions though their established stakeholder processes.44 EEI
does not believe that specific criteria should be developed until a better understanding is
obtained regarding the role of service interruptions as a reliability tool.45 EEI believes
that these are appropriate aspects of the NERC proposal that would be readily amenable
to an initial implementation approach, followed by an adjustment period that would
refine the overall process consistent with the Commission’s concerns.
Commission Determination
30.

We believe that openness and transparency do not alone ensure that bulk electric

system performance criteria will be met to ensure system reliability. The Commission is
not persuaded that developing technical criteria is unachievable. As the Commission
42

NERC Comments at 13.

43

MISO Comments at 3.

44

Id. at 5.

45

EEI Comments at 10.

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observed in the NOPR, NERC has thresholds in other reliability contexts, such as
vegetation management pursuant to Reliability Standard FAC-003-1 which applies to all
transmission lines operated at 200 kV and above. Likewise, NERC’s Statement of
Compliance Registry Criteria includes numerous thresholds for determining eligibility for
registration.46
31.

The Commission does not agree with EEI’s recommendation to implement a

stakeholder process that is absent technical criteria but then amend it later. While the
Commission has, in other circumstances, approved a Reliability Standard and, as a
separate action, directed NERC to develop a modification pursuant to section 215(d)(5)
of the FPA, in such proceedings the Commission concluded that the proposed Reliability
Standard was just, reasonable, not unduly discriminatory or preferential and in the public
interest. In the immediate proceeding, however, we cannot make such a finding in light
of the flawed stakeholder process provision.
32.

In response to MISO’s argument that such criteria should be determined by the

stakeholders in the regions though their established stakeholder processes, the
Commission would be amenable to such an approach if, for example, NERC and/or the
Regional Entities developed an exception process that provides flexibility in decisions
based on disparate topology or on other matters since they could utilize their technical

46

See, e.g., NERC Statement of Registry Criteria, section III. The Commission
approved the Statement of Registry Criteria in Order No. 693. See Order No. 693, FERC
Stats. & Regs. ¶ 31,242 at P 95.

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expertise to determine the reliability impact from one region to another. For these
reasons, the Commission concludes that a more defined process is needed with NERCdefined technical criteria to determine planned interruption of Firm Demand. However,
we conclude that the approach of allowing a decentralized process without any
overarching parameters is unacceptable.
33.

With regard to NERC’s comment that the decision to interrupt local load is

essentially an economic decision that is a quality of service issue, not a reliability issue,
the Commission notes that in Order No. 693, we dismissed the argument that it may be
preferable to plan the bulk electric system in such a manner that contemplates the
interruption of some firm load customers in the event of a N-1 contingency, and that such
interruption is based largely on the matter of economics, not reliability.47
C.

Stakeholder Process
NOPR Proposal

34.

In the NOPR, the Commission expressed concern that NERC’s proposed footnote

‘b’ stakeholder process is insufficient to meet Order No. 693 and the June 2010 Order
clarification that a regional difference, or a case-specific exception process that can be
technically justified, to plan for the loss of firm services at the fringes of the systems is
acceptable in limited circumstances.48 The Commission also noted that nothing in the
proposed footnote ‘b’ defines the stakeholder process, other than that it must be an open
47

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792.

48

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 19.

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and transparent stakeholder process that includes addressing stakeholder comments.49
The Commission noted that any meeting that is open to stakeholders could meet this
criteria.
35.

The Commission further stated that the lack of a defined stakeholder process could

allow a transmission planner to develop a process that provides insufficient opportunity
for stakeholder participation and transparency yet still comply with the standard. The
Commission expressed its belief that nothing in the proposed footnote ‘b’ restricts the
stakeholder process, other than that it must be an open and transparent stakeholder
process that includes addressing stakeholder comments. The Commission requested
comment on whether a stakeholder process is the appropriate vehicle to approve or deny
exceptions to allow entities to plan to interrupt Firm Demand for a single contingency
and if so, whether the proposed footnote ‘b’ would require any stakeholder due process.
Comments
36.

Several commenters believe that NERC’s proposed stakeholder process is the

appropriate venue to approve or deny exceptions to interrupt planned Firm Demand.
NERC and other commenters contend that building on existing stakeholder processes is
appropriate, rather than creating new, duplicative processes. While EEI, APPA, and
TAPS concur with or acknowledge the Commission’s concerns about the inadequacy of
the proposed stakeholder process, they nonetheless urge the Commission to approve

49

Id. P 20.

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NERC’s proposal stating that it reflects the considered expertise that instances of planned
load shed are uncommon and not amenable to a one-size-fits-all approach.50 NERC
believes the introduction of an additional planning process may contribute to further
delays and regulatory confusion. NERC states that “keeping decision-making with those
most impacted by decisions regarding reliability and costs, lack of jurisdictional
authority, and the existence of established open and transparent stakeholder processes –
are the reasons NERC did not create a new stakeholder process.”51
37.

Duke Energy believes that the current Order No. 890-type process involving the

local transmission planning collaborative is the appropriate stakeholder process. Duke
Energy suggests that footnote ‘b’ should be revised to include a local regulatory authority
process as the appropriate stakeholder process to allow entities to plan to interrupt Firm
Demand for a single contingency. According to Duke Energy, in such a process a
transmission planner would submit its plan to interrupt Firm Demand for a single
contingency to its local regulatory authority that has jurisdiction over quality of service to
local load prior to any actual interruption of Firm Demand.
38.

BPA states that the stakeholder process will keep the decision local, where the

parties involved understand the different factors that must be considered in deciding the

50

See, e.g., EEI Comments at 3, TAPS Comments at 5, APPA Comments at 3.

51

NERC Comments at 12.

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proper path forward.52 APPA maintains that these processes impose due process
requirements on the transmission planner, including participation in an open and
transparent stakeholder process that considers stakeholder comments.53
39.

FRCC disagrees with the Commission that enforceability is limited since the

process requires development of a record documenting the decisions and stakeholder
comments and planning authority responses. According to FRCC, the result will provide
NERC and the Commission substantive and procedural grounds to assess whether
sufficient consideration was given to maintaining reliability.54
40.

Some commenters believe that NERC’s proposed stakeholder process is not the

appropriate vehicle to approve or deny exceptions to interrupt planned Firm Demand.
ITC argues that the stakeholder process is inadequately undefined to ensure that planned
Firm Demand interruptions are kept to a minimum. Manitoba Hydro indicates that by
acknowledging an exception for interruptible Firm Demand, NERC appears to recognize
that the right to interrupt is not solely a reliability issue, but also a commercial or legal
issue based on contractual rights.55
41.

While TAPS encourages the Commission to accept NERC’s proposed footnote ‘b,’

it shares the NOPR’s concerns about the adequacy of the open and transparent
52

BPA Comments at 4.

53

APPA Comments at 5.

54

FRCC Comments at 3.

55

Manitoba Hydro Comments at 5.

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stakeholder process and has argued for a decision-making role for transmissiondependent utilities in the Order No. 890 and Order No. 1000 planning processes to ensure
that stakeholder processes do not result in a presentation of a decision followed by the
transmission provider simply “rubber-stamping” the decision.56 If the Commission
determines that these objectives cannot be accomplished without more robust action from
the Commission in this proceeding, TAPS urges the Commission not to remand the
proposed footnote ‘b,’ but instead to accept NERC’s proposal and direct NERC to submit
a further modified footnote ‘b’ to address the parameters of the “open and transparent
stakeholder process that includes addressing stakeholder comments.” 57
Commission Determination
42.

The Commission is not persuaded that the stakeholder process is adequately

defined. The Commission is concerned that the stakeholder process could undermine the
system performance criteria of TPL-002-0b Reliability Standard. As the Commission
stated in Order No. 693, one of the key reliability objectives of the TPL Reliability
Standard is that the system can be operated following the loss of one element and supply
projected firm customer demands and projected firm transmission services at all demand
levels over the range of forecast system demands.58 The Commission finds that the
stakeholder process without appropriate parameters is inconsistent with the reliability
56

TAPS Comments at 5.

57

Id. at 11.

58

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1771.

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objective to supply projected firm customer demands for the loss of one element. While
the Reliability Standard requires that the system is planned so that the system can be
operated following the loss of one element and supply projected firm customer demands,
the proposed stakeholder process could defeat this by allowing a transmission planner to
plan to shed as much load as needed so that the system can be operated to supply
whatever customers remain.
43.

The Commission agrees with TAPS to the extent it observes that the proposal

could allow a transmission planner to utilize a new or existing stakeholder process that
provides insufficient opportunity for a stakeholder to provide meaningful input. We
conclude that the stakeholder process with no criteria to objectively assess whether varied
results are arbitrary or based on meaningful differences is unjust, unreasonable, unduly
discriminatory or preferential, and not in the public interest. Nothing in proposed
footnote ‘b’ defines the stakeholder process, other than it must be an open and transparent
stakeholder process that includes addressing stakeholder comments.
44.

The Commission is not persuaded by FRCC’s comment that enforceability is not

limited by proposed footnote ‘b’ and that development of a record will provide NERC
“substantive and procedural” grounds to assess the outcome of the process. Neither
FRCC nor any other commenter identifies the minimum procedural safeguards to assure
an adequate level of stakeholder participation and consideration of stakeholder comment
in the decision-making process. Moreover, even NERC, which states that it can conduct

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after-the-fact audits, indicates that such audits would not explore substantive adequacy or
the reliability basis for a decision to plan to shed Firm Demand.59 Further, the
Commission is not persuaded by APPA and BPA comments that local stakeholder
participation and due process requirements imposed on the transmission planner are
sufficient. Rather, the Commission believes that if a transmission planner invokes a
process that provides for minimal stakeholder involvement, it could argue that it satisfied
the provision, even if the transmission planner is the ultimate decision maker and simply
‘rubber stamps’ its own proposal to interrupt planned Firm Demand.
D.
45.

Guidance on Acceptable Approaches to Footnote ‘b’

The Commission proposed three options in the NOPR for further guidance on

acceptable approaches to footnote ‘b.’ In addition, the Commission requested comment
on other potential options to solve the concerns outlined in the NOPR.
1.
46.

Existing Protocols to Develop Criteria/Quantitative Limits

In the NOPR, the Commission acknowledged that NERC considered a variety of

limits but observed that NERC’s establishment of some form of criteria for planning to
interrupt Firm Demand could be an acceptable approach for footnote ‘b.’ The
Commission requested comment on whether existing protocols such as the Department of
Energy’s Electric Emergency Incident and Disturbance Report (Form OE-417), which
requires an entity to report a certain amount of uncontrolled loss of firm system loads, or

59

NERC Data Response at 7-9.

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NERC’s Statement of Compliance Registry Criteria could provide guidance to NERC to
devise criteria.
Comments
47.

Commenters were unanimous that the examples of existing protocols would not be

beneficial to devise criteria. NERC and others state that any bright-line megawatt limit
would be inappropriate because the bright-line would be arbitrary.60 Some commenters
do not believe that existing protocols, such as the requirement in Form OE-417 should be
used to determine criteria related to planned loss of Firm Demand.61
48.

BPA, ITC, and Duke Energy comment that setting a quantitative limit would push

transmission planners to plan to meet such a limit for a single contingency in all cases.
Currently, transmission planners start from the premise that no load should be interrupted
in the event of a single contingency. ITC believes that including such an acceptable lost
load criterion as an option could lead to that option being chosen as the “default
solution,” i.e., allowing for a certain amount of acceptable interruption of Firm Demand
without a stakeholder exception review process.62 In the same vein, Duke indicates that a
specific megawatt threshold may prohibit certain interruptions of Firm Demand that
would be acceptable from a quality of service and local consequences perspectives.63
60

NERC Comments at 14.

61

ITC Comments at 5; see also Hydro One and IESO Comments.

62

ITC Comments at 5.

63

Duke Comments at 6.

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Commission Determination
49.

The Commission is persuaded by the commenters that Form OE-417 or the

Registry Criteria are not, by themselves, beneficial to use to devise criteria. The
Commission also agrees that a bright-line criteria by itself does not present a viable
option and would have the potential to constitute an acceptable de facto interruption and
become commonplace to plan to interrupt Firm Demand. For example, if the bright-line
criteria included up to 50 MW of planned interruptible Firm Demand under proposed
footnote ‘b’, then planners may choose to automatically shed up to 50 MW of load as
their first course of action for any single contingency event that would cause a violation
of system performance criteria. This is not an acceptable outcome.
2.
50.

A Blend of Quantitative and Qualitative Thresholds

The Commission also sought comment on whether a blend of quantitative and

qualitative thresholds to be used to interrupt planned Firm Demand would be an
appropriate option for providing criteria that would be generally applicable, but also for
allowing for certain cases that may exceed the criteria. For example, a Reliability
Standard could require a process with a quantitative limitation on how much Firm
Demand could be planned for interruption and the standard could provide an exception
process where a registered entity would submit documents and explanation to the ERO or
a Regional Entity for approval based upon certain considerations.64 The Commission

64

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 18.

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suggested that setting generally applicable criteria for when an applicable entity can plan
to shed Firm Demand, coupled with an exceptions process overseen by NERC and the
Regional Entities, could mean that few exception requests must be processed by NERC
and the Regional Entities.65 The Commission observed in the NOPR that this approach
may satisfy the need for technical criteria while accounting for NERC’s concerns about
the difficulty of developing a one-size-fits-all criterion for limiting planned Firm Demand
interruptions and the appropriateness and feasibility of managing and actively
participating in each planning process.
Comments
51.

California SWP indicates that standards must constrain the use of firm load

shedding as a reliability solution in transmission planning and at the same time, require a
transparent and clearly defined stakeholder process to support any such planned use of
load shedding for single contingency events.66 BPA suggests that, if the Commission
does set a quantitative limit on planned interruption of Firm Demand, a limit based on a
fraction of aggregated normal peak load would be one option that may be more effective
and adaptable to all sizes of utilities.67

65

Id. P 27.

66

California SWP Comments at 2.

67

BPA Comments at 4.

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52.

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Other commenters disagree that a blend is a good option. NARUC indicates that

rather than inventing another stakeholder process by requiring NERC to set specific
quantitative or qualitative requirements for distribution load shedding, NERC should look
to State commissions and existing State curtailment plans to guide load shedding in
contingency planning.68 Duke Energy submits that a blend of quantitative and qualitative
thresholds does not provide enough flexibility to permit the qualitative assessment of the
loads and locations for which transmission planners may interrupt under their exercise of
footnote ‘b’ because a blended threshold may still rely too heavily on a quantitative
threshold for planned interruption of Firm Demand.69 FRCC states it is not feasible to
develop a single quantitative rule that would apply equitably to all stakeholders and
regions.70
53.

EEI believes that adopting a process that would provide greater clarity, reporting,

and refinement would provide the specific information on the extent that the footnote ‘b’
issue presents itself. EEI also agrees with NERC that efforts to create a one-size-fits-all
approach have less value than a process that ensures openness and transparency.

68

NARUC Comments at 3.

69

Duke Energy Comments at 7.

70

FRCC Comments at 7.

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Commission Determination
54.

The Commission believes that setting a quantitative and qualitative threshold in

developing a limited exception for planned interruption of Firm Demand may be a
workable solution. First, qualitative thresholds could be used to overcome the concern
discussed immediately above regarding the quantitative threshold becoming an
acceptable de facto interruption of planned Firm Demand. By utilizing a blend, the
planner must also meet the qualitative threshold which could consist of, for example, the
submittal of documents and explanation to the entity ultimately deciding whether the
planned load shed is acceptable. For example, if 100 MW of planned Firm Demand was
permitted to be interrupted, the planner could not automatically and unilaterally shed up
to 100 MW of planned Firm Demand each time system performance criteria would be
violated. Under the blend concept, the Commission envisions that the planner would
consider up to 100 MW of planned Firm Demand interruption along with other options to
resolve the system performance criteria violation and submit its documentation and
explanation to the entity deciding whether the planned load shed is acceptable. The
concept of a blend of thresholds would prevent an acceptable de facto interruption of
planned Firm Demand and avoid the difficulty of developing a one-size-fits-all criterion
for limiting planned Firm Demand interruptions, but still allow for those limited
circumstances to be reviewed in an exception process where a limited amount of planned
interruption of Firm Demand may be acceptable.
55.

We believe it is appropriate for the Regional Entities, with NERC as the final

authority, to make determinations under a “blended” exception process. First, NERC and

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the Regional Entities provide both objectivity in the decision-making process as well as
the necessary reliability-focused expertise. Second, this should not overly burden NERC
or Regional Entity resources as utilization of the planned load shed exception is – and
would be – rarely utilized.71 Further, we are not persuaded by the assertion that NERC
would be conflicted as the ERO and also inserting itself in the process. NERC’s ERO
role would continue, in coordination with its current responsibilities in implementing
other exceptions such as the Technical Feasibility Exception process under the Critical
Infrastructure Protection Reliability Standards.
56.

The Commission does not agree with BPA’s suggestion of using quantitative

thresholds based on a fraction of aggregated normal peak load. BPA’s suggestion
attempts to address the concerns of commenters that a bright-line threshold must be
established that would be a one-size-fits-all criteria. For example, instead of a megawatt
bright-line threshold for all entities, the ERO could establish a threshold based on a
percentage of aggregated normal peak load. The Commission believes that it would be
difficult to demonstrate that adoption of BPA’s suggestion would be just and reasonable,
not unduly discriminatory or preferential and in the public interest. If criteria were
established that permitted a percentage of aggregated normal peak load as an acceptable
threshold for planned interruption of Firm Demand, even a small percentage could equate

71

See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA Comments.

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to entire towns, cities or regions of load.72 The Commission, therefore, does not support
the planned interruption of Firm Demand based on a fraction of aggregated normal peak
load. The Commission believes that an appropriate mechanism would be based on
impact studies that consider minimizing planned interruption of Firm Demand within,
and adjacent to, communities and small localities.
57.

The Commission offers guidance to NERC to consider the option of a blend of

quantitative and qualitative thresholds. An example of a qualitative threshold could
include identifying geographical or topological “fringes of the system.” While
interruption at the fringes of the system may be expected by some consumers, not all
customers necessarily have that same expectation. For example, we don’t expect that
many water treatment facilities or telecom switching stations normally plan to be
interrupted for single contingency events.73 While the Commission has offered one
example of a qualitative threshold, NERC may explore other qualitative thresholds on
remand. The Commission believes that a blend of quantitative and qualitative thresholds
coupled with an exception process overseen by NERC and the Regional Entities would
be a reasonable option to allow for the limited interruption of planned Firm Demand.

72

For example, the PJM aggregated normal system peak load is approaching
160,000 MW, so a one percent threshold would equate to allowance of planned
interruption for a single contingency of up to 1600 MW of load, which is the size of some
entire towns, cities or regions.
73

While we anticipate that such facilities are prepared for distribution-level
blackouts, we are not aware that they are prepared for a transmission-level blackout.

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Accordingly, the Commission directs the ERO to consider some blend of quantitative and
qualitative thresholds.
3.
58.

Customer or Community Consent

In the NOPR the Commission also requested comment on whether a feasible option

would be to revise footnote ‘b’ to allow for the planned interruption of Firm Demand in
circumstances where the “transmission planner can show that it has customer or
community consent and there is no adverse impact to the Bulk-Power System.”74 The
Commission suggested that this would not require affirmative consent by every
individual retail customer, but would recognize that either group would need to be
adequately defined. The Commission requested comments on who might be able to
represent the customer or community in this option and how customer or community
consent might be demonstrated.75 The Commission also requested comment on how it
would be determined that firm demand shedding with customer consent would not
adversely impact the Bulk-Power System. Additionally, the Commission requested
comment on whether a customer who would otherwise consent to having its planning
authority or transmission planner plan to interrupt Firm Demand pursuant to this option
could instead select interruptible or conditional firm service under the tariff to address
cost concerns.

74

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 28.

75

Id.

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Comments
59.

Several commenters agreed with the Commission that the customer or community

consent should be required. ITC believes the customers or entities should be involved in
a stakeholder process such as a representative group for the affected load or customers
(community representatives or a separate load serving entity where the transmission
provider is not an integrated utility), the public service/utility regulatory commission for
the affected load, the RTO or ISO for the affected area, and any other affected entity.
California SWP also supports notice to and consent of loads (or their wholesale
representatives) that are planned to be interrupted for the loss of a single element.76 In its
comments, California SWP explains that it was “surprised to learn that in lieu of
transmission upgrades, [its transmission planner] relied on interruption of SWP’s large
firm pump loads supposedly receiving the same California Independent System Operator
(CAISO) transmission service as provided to SCE loads. At that time, SWP was not
consulted about the planned curtailment of its firm loads as an alternative to a
transmission upgrade, and thus had no opportunity to correct this error.”77
60.

Other commenters disagree that customer or community consent should be

required. NERC states that it has no relationship with retail customers and, therefore, has
no mechanism to bring retail customers into the conversation. NERC adds that both

76

California SWP Comments at 4.

77

Id. at 2-3.

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wholesale and retail customers are already involved in state processes which provide a
forum for them to be heard.
61.

Hydro One and the IESO submit that customer interests are managed by the

relevant regulatory authority and consent is through regulatory approval. In all cases,
steps are taken in planning, design, and operations of the system to ensure that Firm
Demand shedding would not adversely impact the bulk electric system in addition to the
fact that the customer also has other options such as to select interruptible service.
NYPSC recommends that the Commission only prescribe acceptable load shedding as it
pertains to wholesale customers that are in a position to select interruptible or conditional
firm transmission service under Commission-approved tariffs.
62.

FRCC states that the evaluation of the possible use of interruptible or conditional

firm service instead of planned interruptions of Firm Demand is not warranted.
According to FRCC, the adoption of a Firm Demand interruption alternative would
inherently entail customer benefits from foregone project costs and the non-incurrence of
environmental and other impacts. The customers would also generally enjoy a higher
quality of service than traditional interruptible or conditional firm. Consequently, FRCC
believes that applying any such rate in place of Demand interruption would present
imponderable issues of quantification and application.
63.

BPA does not believe that this proceeding is appropriate to decide issues related to

service choice. BPA argues that the Commission has determined that the rate for
conditional firm service be the same as the firm rate. BPA does not anticipate that the
interruption of Firm Demand would occur on a frequent basis, if at all. Thus, BPA does

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not believe that a customer should pay a different transmission rate under these
circumstances. APPA states that footnote ‘b’ arms wholesale transmission customers and
communities served at retail with information and studies prepared by the transmission
planner, documenting the specific circumstances (i.e., specific Bulk Electric System
Contingency events) under which interruption of Firm Demand may be needed to address
bulk electric system performance requirements.
Commission Determination
64.

We understand NERC’s position that as the entity that addresses Bulk-Power

System reliability, it does not have a mechanism to coordinate with customers. Likewise,
how to define customers and community decisions and engage them in the NERC process
could be challenging.78
65.

At the same time, California SWP provides a compelling example of how a

customer can be adversely affected by planned load shedding for Firm Demand if it was
unaware its load would be interrupted until its load was actually shed. In contrast to
California SWP’s experience, a customer should have notice and understanding that the
transmission planner plans to curtail certain Firm Demand in the event of a single

78

As suggested in the NOPR, customer or community consent would not require
affirmative consent by every individual retail customer, but the process NERC developed
would recognize that either group would need to be adequately defined. We note that,
although NERC comments that it addresses Bulk-Power System reliability, the process
that NERC proposes will impact firm load service to retail customers.

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contingency indentified in the system modeling under NERC’s Transmission Planning
requirements. NERC should consider these matters on remand.79
Summary
66.

In sum, the Commission remands the proposed footnote ‘b’ and directs NERC to

revise its proposal to address the Commission’s concerns described above, subject to
consideration of the additional guidance provided in this Final Rule.
67.

As stated in the NOPR, NERC will need to support the revision to footnote ‘b.’ If

there is a threshold component to the revised footnote, NERC would need to support the
threshold and show that instability, uncontrolled separation, or cascading failures of the
system will not occur as a result of planning to shed Firm Demand up to the threshold. In
addition, if there is an individual exception option, the applicable entities should be
required to find that there is no adverse impact to the Bulk-Power System from the
exception and that it is considered in wide-area coordination and operations. Further, the
Commission believes that any exception should be subject to further review by the
Regional Entity or NERC.
III.

Information Collection Statement

68.

The Office of Management and Budget (OMB) regulations require that OMB

approve certain reporting and recordkeeping (collections of information) imposed by an

79

We will not consider the tariff-related comments as they are beyond the scope of
this rulemaking.

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agency.80 The information contained here is also subject to review under section 3507(d)
of the Paperwork Reduction Act of 1995.81
69.

As stated above, the subject of this Final Rule is NERC’s proposed modification to

Table 1, footnote ‘b’ applicable in four TPL Reliability Standards. This Final Rule
remands the footnote ‘b’ modification to NERC. By remanding footnote ‘b’ the
applicable Reliability Standards and any information collection requirements are
unchanged. Therefore, the Commission will submit this Final Rule to OMB for
informational purposes only.
70.

Interested persons may obtain information on the reporting requirements by

contacting the following: Federal Energy Regulatory Commission, 888 First Street,
NE, Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director,
e-mail: [email protected], phone: (202) 502-8663, or fax: (202) 273-0873].
IV.

Environmental Analysis

71.

The Commission is required to prepare an Environmental Assessment or an

Environmental Impact Statement for any action that may have a significant adverse effect
on the human environment.82 The Commission has categorically excluded certain actions
from this requirement as not having a significant effect on the human environment.
80

5 CFR § 1320.11.

81

44 U.S.C. § 3507(d).

82

Regulations Implementing the National Environmental Policy Act of 1969,
Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations
Preambles 1986-1990 ¶ 30,783 (1987).

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Included in the exclusion are rules that are clarifying, corrective, or procedural or that do
not substantially change the effect of the regulations being amended.83 The actions
proposed herein fall within this categorical exclusion in the Commission’s regulations.
V.

Regulatory Flexibility Act

72.

The Regulatory Flexibility Act of 1980 (RFA)84 generally requires a description

and analysis of final rules that will have significant economic impact on a substantial
number of small entities. The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small Business
Administration’s (SBA) Office of Size Standards develops the numerical definition of a
small business.85 The SBA has established a size standard for electric utilities, stating
that a firm is small if, including its affiliates, it is primarily engaged in the transmission,
generation and/or distribution of electric energy for sale and its total electric output for
the preceding twelve months did not exceed four million megawatt hours.86 The RFA is
not implicated by this Final Rule because the Commission is remanding footnote ‘b’ and
not proposing any modifications to the existing burden or reporting requirements. With
no changes to the Reliability Standards as approved, the Commission certifies that this
83

18 CFR § 380.4(a)(2)(ii).

84

5 U.S.C. § 601-612.

85

13 CFR § 121.201.

86

Id. n.22.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 43 -

Final Rule will not have a significant economic impact on a substantial number of small
entities.
VI.

Document Availability

73.

In addition to publishing the full text of this document in the Federal Register, the

Commission provides all interested persons an opportunity to view and/or print the
contents of this document via the Internet through FERC's Home Page
(http://www.ferc.gov) and in FERC's Public Reference Room during normal business
hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A,
Washington DC 20426.
74.

From FERC's Home Page on the Internet, this information is available on eLibrary.

The full text of this document is available on eLibrary in PDF and Microsoft Word
format for viewing, printing, and/or downloading. To access this document in eLibrary,
type the docket number excluding the last three digits of this document in the docket
number field.
75.

User assistance is available for eLibrary and the FERC’s website during normal

business hours from FERC Online Support at (202) 502-6652 (toll free at 1-866-2083676) or email at [email protected], or the Public Reference Room at (202)
502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
VII.

Effective Date and Congressional Notification

76.

These regulations are effective [insert date 60 days from publication in FEDERAL

REGISTER]. The Commission has determined, with the concurrence of the

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 44 -

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule
is not a “major rule” as defined in section 351 of the Small Business Regulatory
Enforcement Fairness Act of 1996.
By direction of the Commission. Commissioner Norris is dissenting in part and
concurring in part with a separate statement attached.
(SEAL)

Kimberly D. Bose,
Secretary.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Transmission Planning Reliability Standards

Docket No. RM11-18-000

(Issued April 19, 2012)

NORRIS, Commissioner, dissenting in part and concurring in part:
The continued implementation and evolution of the mandatory reliability
standards program enacted by Congress in 2005 has been at the forefront of our agenda
since I arrived at the Commission in 2010. As we have grappled with the difficult issues
raised by proposed new or revised standards, and as I have discussed these issues with
regulated industry, state regulators, and the public, I have consistently heard a common
theme: mandatory reliability standards come with costs that consumers ultimately must
bear.
As I have thought about this issue, it has become clear to me that in any discussion
of a new or revised mandatory reliability standard, there is always a tradeoff between the
level of reliability to be achieved by that standard and the costs that the standard will
impose. However, that tradeoff is rarely discussed explicitly in the standards
development process or during the Commission’s review of standards. But, we know
that it is an implicit consideration of entities participating in the standards development
process. I believe it is more appropriate to make those considerations, where they are
relevant, explicit. Therefore, I have advocated for an open dialogue between NERC, the
industry, and the Commission to consider the connection between the mandatory
standards we approve to maintain and improve the reliability of the Bulk Power System
and the costs required to meet those standards.
However, I have perceived some hesitancy in openly addressing costs when
considering reliability matters. This is not surprising, as there are no easy answers to
these tough questions, and regulators and industry charged with assuring reliability will
always be hesitant to be perceived as sacrificing reliability in an effort to save on costs.
While I am not advocating for a cost-benefit threshold for approving reliability standards,
I do not believe that we can ignore the costs of proposed mandatory reliability standards
as we consider whether they are “just, reasonable, not unduly discriminatory or
preferential, and in the public interest”.1 These are issues with real world implications,
1

See 16 U.S.C. 824o(d)(2).

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--2-not just for the reliability and security of our Nation’s electric grid, but for the day-to-day
struggles of local communities to balance the economic realities of many competing
obligations.
I am compelled to raise these issues in this proceeding because I believe that the
Transmission Planning (TPL) Reliability Standard footnote ‘b’ addressed in today’s order
presents a stark example of the tradeoffs that sometimes must be made between
increasing levels of reliability and the costs that come with achieving them. As such, I
hope my comments today will help generate a dialogue on how economics and reliability
fit together when considering mandatory reliability standards.
In today’s order, I agree with the majority’s decision to remand proposed TPL
footnote ‘b’ because it is vague, potentially unenforceable, and lacks adequate safeguards
to determine when planning to shed firm load would be permitted. However, I am
concerned that, in allowing for an exception to the TPL standards requirement that firm
load must be maintained under N-1 scenarios, the order does not sufficiently recognize
that this is both an economic and reliability issue, and must allow for a balancing of the
economic and reliability considerations involved.
There may be cases where planning to avoid shedding firm load in all N-1
scenarios will impose significant costs on customers, with perhaps little added reliability
benefit for those customers. In such instances, I believe that wholesale transmission
customers and local communities with retail load service should be empowered to
consider the economic tradeoffs between incurring costs to avoid shedding firm load
versus planning to shed firm load, as long as that decision does not adversely impact the
reliability of the Bulk Power System. Simply put, if a customer seeks to avoid significant
costs, and can do so without impacting its neighbors, the customer should be making that
decision. Today’s order fails to adequately acknowledge the economic consequences of
having to invest in significant facility upgrades to avoid shedding firm load under certain
N-1 scenarios that may be rare or unlikely and that would have only local impacts.2
2

Transmission Planning Reliability Standards, Order No. 762, 139 FERC ¶
61,060, at P 33 (2012) (“With regard to NERC’s comment that the decision to interrupt
local load is essentially an economic decision that is a quality of service issue, not a
reliability issue, the Commission notes that in Order No. 693, we dismissed the argument
that… such interruption is based largely on the matter of economics, not reliability.”) I
also note that the brief Commission findings in Order No. 693 failed to acknowledge or
sufficiently address this issue, leaving the uncertainty we are still faced with today.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats.
& Regs. ¶ 31,242, at P 1791-1794 (2007).

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--3-Accordingly, in my view, the Commission should have directed NERC to revise
footnote ‘b’ to address two broad concerns. First, wholesale transmission customers and
retail load should have the ability to choose whether to shed firm load during an N-1
contingency where that decision will not adversely impact the Bulk Power System.
Second, the decision to shed firm load must be validated to ensure that there is no adverse
impact on the Bulk Power System. Absent this reliability check, the planning of firm
load shedding should not be permitted, because reliability of the Bulk Power System is
paramount. While NERC, the Regional Entity, and/or the local planning authority must
be involved in the reliability check, these entities would not be expected to be involved in
the economic decision.
Additionally, I agree with various comments filed in response to the NOPR that
firm load shedding is and should be used rarely or infrequently. I do not expect that any
new process that NERC may propose to determine whether firm load shedding is
permitted would result in a rush by entities seeking to plan to shed firm load. In other
words, I do not expect this exception to “swallow the rule” under the TPL standards that
firm load may not be planned to be shed for N-1 contingencies.
Finally, the concerns I note above regarding the failure to consider both the
economic and reliability aspects of a decision to plan to shed firm load extend to the
specific guidance provided in the order. The guidance in the order with respect to what
would constitute an allowable exception fails to provide a realistic means for entities to
balance these economic and reliability considerations. Instead, I would have provided
that an entity could submit its plan to shed firm load for a single contingency to its
relevant regulatory authority or governing body prior to any actual interruption.3 The
politically accountable regulatory authority or governing body would have then made the
determination, based upon economics and in the best interests of its customers, as to
whether firm load shedding should be permitted. Those determinations would be subject
to oversight and review by NERC, the Regional Entity, and/or the planning authority to
ensure that they will not adversely impact the Bulk Power System.4

3

See e.g., Duke Energy Corporation Dec. 22, 2011 Comments, Docket No.
RM11-18-000.
4

NERC may propose an alternative to Commission guidance that is equally
efficient and effective at addressing the Commission’s reliability concerns. Order No.
693 at P 31.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--4-For these reasons, I respectfully dissent in part and concur in part.

_____________________________
John R. Norris, Commissioner

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Document Content(s)
RM11-18-000a.DOC......................................................1-50

Standards Announcement

Project 2010-11– TPL Table 1 Order
TPL-002-1b, footnote ‘b’ and TPL-001-3, footnote 12
Formal Comment Period Open: July 31, 2012 – August 29, 2012
Now Available
A formal comment period for TPL-002-1b – Single Performance Following Loss of a Single BES Element
for footnote ‘b’ and TPL-001-3a – Transmission System Planning Performance Requirements for
footnote 12 is open through 8 p.m. Eastern on Wednesday, August 29, 2012.
Instructions for Commenting

A formal comment period is open through 8 p.m. Eastern on Wednesday, August 29, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic
form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the
comment form is posted on the project page.
Next Steps

Data Request to Transmission Planners and Planning Coordinators
A draft data request to collect data to assist the SDT in its work was posted for an abbreviated
comment period in accordance with Section 1600 of the NERC Rules of Procedure, through July 9,
2012. The draft data request was revised as appropriate to reflect industry comments and is being
issued for formal response concurrent with this posting. The timing of the formal data request
response will allow for the data to be evaluated by the SDT in the same timeframe as the responses to
this posting.
The drafting team will consider all comments and determine whether to make changes. If the drafting
team does not make significant changes, the standards will be posted for a 45-day comment period
and initial ballot.
Background

FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following

the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Individual or group. (53 Responses)
Name (41 Responses)
Organization (41 Responses)
Group Name (12 Responses)
Lead Contact (12 Responses)
Contact Organization (12 Responses)
Question 1 (45 Responses)
Question 1 Comments (49 Responses)
Question 2 (45 Responses)
Question 2 Comments (49 Responses)
Question 3 (44 Responses)
Question 3 Comments (49 Responses)
Question 4 (45 Responses)
Question 4 Comments (49 Responses)
Question 5 (0 Responses)
Question 5 Comments (49 Responses)

Individual
hello
NAT
Group
TVA Transmission Reliability Engineering & Controls
Tim Ponseti, VP
Bulk Transmission Engineering
No
TVA believes that the Stakeholder process is burdensome and should not be required for all levels of
footnote b use. TVA beleives that the Stakeholder process should only be used for larger amounts of
planned load drop. TVA would like to propose the following: For load loss of less than 50 MW - only TP
approval is required; for load loss up to 100 MW - PC approval is required; for load loss up to 300 MW
- RRO approval is required. Any load loss over 300 MW would require both RRO & NERC approval. The
Stakeholder process would be required for any load loss of 100 MW or more. TVA is basing these
levels using OE-417 as a starting point - which must be filed for an uncontrolled load loss of 300 MW
as well as load shedding of 100 MW or more implemented under emergency operational policy. TVA
believes that the 300 MW is the maximum amount of load that can be dropped without obtaining
special permission from both NERC and the RRO.
No
Please see comment for question #1. TVA believes that TPs should be able to drop some load without
having to go thru a burdensome process. Only the larger load drop levels should require a
Stakeholder review.
No
Under Item #2 - TVA is not sure how to properly address “health, safety, and welfare of the
community” from an regulatory standpoint. Please clarify what this would require - such as number of
hospitals without emergency backup, etc? Also please see answer to question #1 - TVA beleives that
only larger load drops should require a Stakeholder review.
No
Please see answer to question #1. TVA believes that the requirements of 25 MW as well as any Bulk
contingency over 300-kV is much too burdensome. TVA beleives that only larger load drops should
require a Stakeholder review.
Please see answer to question #1. TVA beleives that only load drops of higher magnitudes go thru the
Stakeholder and regulatory review.
Group
Puget Sound Energy
Sunitha Kothapalli

Transmission Planning
Individual
Aaron Staley
Orlando Utilities Commission
Yes
Yes
Yes
Data element 5 should probably read. "List any Future Plans or future system changes to mitigate the
need for Firm Demand Interruption under footnote 'b'". There can be cases where there is no planned
future project to relive the problem, or it could be expected that load will go down or changes on
neighboring systems will relieve the problem.
Yes
Comment #1: The maximum threshold should be in the Footnote, not in the Attachment. Comment
#2: I think the role identified for the Regional Entity is appropriate. Comment #3: I like the concept
that regulatory approval is not required until year one. However I think either the ordering of
language or the formatting needs to be changed to make it clear that the year one applies to only
those that need regulatory approval. Maybe change the section to read... "Section III Firm Demand
Interruptions under footnote 'b' that meet either or both of the criteria below are required to have
approval by the applicable regulatory authority or governing body responsible for retail electric
service issues. The regulatory approval is required prior to the use of that remedy in Year One of a
Corrective Plan in the Planning Assessment. (Existing 1 & 2) (Existing RE Review)
Individual
Chifong Thomas
BrightSource Energy, Inc.
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns and different authorities. For example, how would such a dispute resolution process
take into account the cost-benefit balance of load loss, which is the responsibility of the authorities
responsible for approving retail rates, if such an authority is only one of the many stakeholders
subject to dispute resolution?

No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV inconsistent with P1. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 2 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column. The new
definition of Non-consequential Load Loss compared to the last version seems to have deleted the
reference to Loads that may be lost during transient conditions due to under-frequency load shedding
(UFLS), while the reference to Load Loss due to under-voltage load shedding (UVLS) is retained. As a
result Load Loss due to UFLS would be part of Non-consequential Load Loss, and will not be allowed
under single contingency. Because UFLS may also be triggered during transient simulations, please
change the definition for Non-consequential Load Loss to read: “Non-Consequential Load Loss: NonInterruptible Load loss that does not include: (1) Consequential Load Loss, (2) the response of
voltage sensitive Load or frequency sensitive Load, or (3) Load that is disconnected from the System
by end-user equipment.” It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting steady state
reliability requirements. Therefore, in Table 1, please change header-note “i” to read: “The response
of voltage sensitive Load and Frequency sensitive Load that is disconnected from the System by enduser equipment associated with an event shall not be used to meet steady state performance
requirements.”
Individual

Jose H Escamilla
CPS Energy
Yes
Yes
Yes
Yes

Individual
Mark Westendorf
MISO
No
Transmission planning that relies on planned or controlled interruption of non-consequential firm load
following loss of a single transmission facility should not be acceptable and removal of footnote 12
should be considered or a modification to allow its use only in conjunction with a petition to FERC to
waive (on an exception basis) the requirement to maintain firm load service for a specifically
identified system configuration issue warranting Footnote 12’s application. If it is determined that a
footnote provision is required in the standard, we agree with the description and components of the
Stakeholder Process in the body of the footnote, but reserve judgment on the value of the “x” that
sets the maximum amount of MW load loss. Also, we have comments on the reference to Attachment
I. Please see our comments under Q5.
No
(1) The process presented in Section I of Attachment I is overly prescriptive. This Section needs only
to stipulate that the proposed utilization of the footnote be reviewed through an open and transparent
stakeholder process developed or approved by the Regional Entities (since the RE will eventually need
to review and assess the reliability impact of such utilization), with supporting information. (2) There
is no basis to support allowing the utilization of the footnote in the Near-Term Transmission Planning
Horizon of the Planning Assessment only. The footnote itself leaves the time frame wide open, and
does not explicitly or implicitly restrict its utilization to only the Near-Term horizon. Often, in the longterm planning horizon, when approval for transmission addition or reinforcement cannot be obtained
for whatever reasons, utilization of the footnote is considered and adopted, subject to stakeholder’s
and regulatory authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year 0ne) time frame and hence the proposed provision does
not allow for utilizing the footnote for the interim period before new or reinforced transmission
facilities are put in place. We suggest to remove the word “Near-Term”. (3) Requirement 8 of the
Transmission Planning Standard TPL-001-3 requires notification and response requirements for a
Planning Coordinator and/or Transmission Planner for the Planning Assessment to any registered
entity having a reliability interest. Attachment I does not recognize this requirement. Attachment I
must be coordinated with this administrative requirement.
No
Again, this Section is overly prescriptive. This Section needs only to stipulate at a high level, the kind
of information needed to support the proposed utilization of the footnote, leaving much of the detail
to the application process overseen by the Regional Entities (given the RE will eventually need to
review and assess the reliability impact of such utilization). We suggest the SDT to reduce this
Section, or remove this altogether with appropriate insertion into Section I that address a general
need for supporting information to be specified by the RE’s review process.
No
We generally agree with the instances for which approval or interruptions is required, but do not
agree with the requirement to seek regulatory approval. In general, when the footnote is proposed to
be utilized as an interim measure until transmission facilities can be added or reinforced, regulatory
approval must be sought in advance. Having this requirement in a reliability standard not only is

unnecessary, but also introduces regulatory requirements (which provides no reliability benefit or
basis) in a reliability standard. NERC reliability standards should focus only on BES reliability, not any
regulatory requirements. Section III should therefore stipulate a high-level requirement for the
proposing entity to submit the proposal to the RE for review and concurrence. Along with the
submission, the RE may require the proponent to include a copy of appropriate regulatory approval
(which the entity should have already obtained). The conditions (1) and (2) for seeking regulatory
approval can be retained, but now become the criteria for seeking review and concurrence by the RE.
Additionally, Attachment 1 requires that the ERO develop a methodology on evaluation criteria to be
published for determining Adverse Reliability Impacts for approval by the ERO. Planning Assessments
are performed on an annual basis. The Attachment 1 process and ERO methodology may require a
lengthy approval process that must be repeated on an annual basis.
(1) The process described in Attachment 1 may be more suited for inclusion in the Rules of Procedure,
similar to the process required for seeking BES facility exceptions. We urge the SDT to consider
moving Attachment 1 into a proposed RoP instead of stipulating it in the standard. (2) It may be more
appropriate to develop a Standards process that covers the technical aspects of using a footnote 12
and leave regulatory review and approval to FERC and State agencies.
Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council

NPCC reviewed the posted documents, and has no comments for this posting.
Individual
Jennifer Wright
San Diego Gas & Electric
No
We don’t support the changes.
No
We don’t support the addition of stakeholder process language.
No
We don’t support the addition of stakeholder process language.
No
In FERC Order 762, FERC rejected NERC’s footnote (b) and urged “…NERC to develop modifications
responsive to the Commission’s directives in Order No. 693 and our concerns set forth in this final
rule.” The NERC SDT has done little to address FERC’s concerns and instead has resubmitted the
same document with additional language. Order 693 directed NERC to develop modifications to TPL002-0, which clarify footnote (b). As redrafted, footnote (b) does not address FERC’s concerns. For
example, footnote (b) continues to use the term “Firm Demand,” which describes all forms of demand
whether served by the faulted element or not. On the contrary, “consequential load loss” is load,
which is removed as a result of a fault. Clearly, these are different concepts and the new language
does not comply with FERC’s directive. FERC’s position has been that non-consequential load loss
through load shedding shall not be allowed as an exception to TPL-002-0. Also, FERC has stated that
the interruption of Firm Transmission not be allowed as an exception. But, Footnote (b) continues to
say, “Curtailment of firm transfers is allowed …”. Another inconsistency. Beyond the differences
between what FERC directed NERC to do and what NERC did, as written, footnote (b) would introduce
“stakeholder interests” into tranmission reliability even if those interests do not promote reliability.
The TPL standards identify the Planning Authority and Transmission Planner as the entities
responsible for meeting the standards and makes no mention stakeholders. To meet the reliability
objectives of the standard, the Planning Authority and Transmission Planner are subject to Measures

and the Compliance Monitoring Process. In FERC Order 762, FERC determined “…that openness and
transparency do not alone ensure bulk electric system performance criteria will be met…” and was
“…not persuaded that developing technical criteria is unachievable.” Although FERC does not disagree
with adding a stakeholder process, clearly, they do not endorse one and prefer a technical approach
to creating the exception under footnote “b”.
Individual
Patrick Brown
Essential Power, LLC
No
Although we agree with the majority of the content of the footnote, we’re not sure that using a
specific amount of load as the bright-line threshold is appropriate. For example, if we make the limit
25 MW, this will have a different impact on different entities, in different regions. For a small TP that
may only have a total of 200 MW of load, 25 MW is a significant amount of their overall obligation. For
an area with 40,000 MW of load, 25 MW is hardly significant. Additionally, the nature of the load must
be taken into consideration as well. Some types of load are more acceptable to lose than others;
again, this may vary from region to region. Although we don’t have a specific recommendation or
solution regarding these issues, I would urge the SDT to take these into consideration in their next
revision. The sentence that starts with “When interruption of Firm Demand is utilized…” is confusing
as it seems this sentence should only refer to the limited circumstances mentioned within footnote b
Yes
Yes
No
This solution requires filing with a regulatory body for any extra interruptions. This seems to be a lot
of effort and language for a contingency event that the system is supposed to be able to handle.
As written, this change is complex and will be difficult to execute without additional turmoil on the
planning end and offers limited clarification. Some additional issues to consider; 1. Should this level of
contingency allow isolation/removal of load or generation if not part of the outage? 2. Should
additional generation be allowed to be removed, again considering the contingency level?
Group
Southwest Power Pool Reliability Standards Development Team
Jonathan Hayes
Southwest Power Pool
Yes
As a concept we agree with the stakeholder process. We would like clarification on why only the Near
Term was used for non-consequential load loss and not both Near and Long term. It seems that
depending on the time frame we would be held to different requirements of the standard.
Yes
See comment From question 1
No
We need clarification on the term planner in item 8 of section 2. Since the term isn’t capitalized we
would like to know if this was intended to mean Transmission Planner or a adjacent Planning
Coordinator for identifying a seams issue. We would like see item 2b of section 2 removed this item
isn’t relevant to the standard and goes beyond the purpose of this standard. We understand that this
is included for curtailment of load during emergency conditions (EOP001 Attach 1) but feel it is
unnecessary in planning.
No
Need clarification around why the 25MWs threshold on generation was thrown into load interruption
topic. Looking at the registry criteria for generation the threshold should be 20Mws for a single unit
and 75 MWs for aggregated units. Not sure where the 25MWs threshold came from for generation.
The 25 MW threshold in Section III is duplicative of the registration limit for generation in the ERO
Statement of Compliance Registry Criteria. It is submitted for comment at this time but will not be

finalized until after the above mentioned data request is complete and the final value will be
submitted for industry comment and approval in the next posting. The GOP registration criteria is
20MWs. Whereas the registration criteria for LSEs and DPs is 25MWs. There appears to be some co
mingling of criteria. Additionally this raises the question of whether x =25MWs. Please clarify which
you intended to use. We are concerned that getting retail service regulatory authority approval in a
quick manner could be difficult. We are also concerned that if it does get caught in the process of
being approved and there is no time to construct, that we would not want to be found out of
compliance due to something that is out of our control.
We agree the distinction between consequential and non- consequential is necessary. We don’t agree
that you should plan for non-consequential load loss/shed. You shouldn’t have to interrupt firm
service for n-1 contingency.
Individual
Keith Morisette
Tacoma Power
No
The layout of Table 1 with “No 12” does not actually indicate that load loss is allowed for those
specific contingencies. Also the wording of the footnote appears to require all Non-Consequential Load
Loss to go through the attachment 1 process, not just P1.1 to P1.5, P2.1 and P3.1 to P3.5. Instead
P1.1 to P1.5 and P3.1 to P3.5 should say “Yes per Attachment I” and Footnote 12 should be
eliminated entirely. Since P2.1 is a new requirement with Version TPL-001-03, the recent NERC
survey did not capture utilities currently using Non-Consequential Load Loss to address opening a line
without a fault. Furthermore, some utilities may not identify problem lines until their first assessment
using TPL-001-3. P2.1 should have a new footnote reading “For this contingency, load which is served
radial from a remaining single source line may be shed as if it were Consequential load.” Technical
Background: Parallel transmission lines serving remote load commonly will not perform with a P2-1
contingency, particularly when the strong source is opened. These issues are particularly common
with load in rural settings and the cost to meet urban reliability expectations will be disproportionally
expensive. Utilities will be encouraged to configure their system radially, which will be less reliable to
meet this rare contingency. FERC has not specifically addressed load shedding associated with open
ended lines. In order 693 the Commission was responding to the contingencies in TPL-001-1 that
included footnote b. In order 762 and the NOPR RM12-1-000, FERC continues to reference
applicability of footnote b to the TPL-001 defined single contingencies, but was otherwise prepared to
accept Firm Load Loss for the single contingencies in TPL-001-2 P2.2 to P2.4. In the TPL-001-2, the
category of “P2-Single Contingency” expanded to include both a new contingency of an open ended
line, and various bus and breaker faults that previously were considered as Multiple Contingency.
Based on our experience the likelihood of a line opening is significantly less than for line equipment
faults. In addition, during human error caused line open events, personnel are on-site to affect quick
restoration. This standard should not impose an upper limit because any planned large load shedding
will be reviewed and approved by the applicable regulatory authority. Pending the survey outcome, a
limit of 3000 MW consistent with the CIP-002-5 Critical Asset level may be useful if the SDT believes
an upper limit is needed.
No
Completing the entire stakeholder process on an annual basis, before the TPL study can be finalized,
is not feasible due to long and unpredictable timelines for public involvement and regulatory approval.
The stakeholder process should only be repeated when the technical basis as outlined in section II
have changed, or when there are new stakeholders. There are cases on the fringes of the system
where Firm Demand Interruption as the preferred alternative in both the long term and short term,
not as a temporary patch in Corrective Action Plan. To address these issues, Section I should read as:
Before the use of Firm Demand interruption is allowed as an element in the Transmission Planning
Horizon of the Planning Assessment, the Transmission Planner or Planning Coordinator shall ensure
that the utilization of this mitigation is reviewed through an open and transparent stakeholder
process. The responsible entity shall document the stakeholder process which shall include the
following: 1. Meetings must be open to all 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 all 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 applications of the planned Firm Demand
interruption under footnote 12 c. Provisions for a stakeholder comment period 3. Information
regarding the intended purpose and scope of the proposed Firm Demand interruption 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. During each Planning Assessment,
the Transmission Planner or Planning Coordinator shall update the information outlined in Section II.
If the annual hours of exposure to or the amount of Firm Demand has increase above the previously
disclosed level(s), a new Stakeholder process shall be completed within one Calendar year. Every
three years the stakeholder process shall reoccur to allow new stakeholders input to the process.
No
Item II.2.b Since this is a stakeholder process, each stakeholder can make an assessment for
themselves about the effect of Firm Demand interruption on the health, safety and welfare of the
community. This requirement is too vague to be enforceable. Item II.5 Particularly in the case of P2.1
contingencies, utilities may not have any plans to eliminate load shedding “at the fringes of various
systems” as the FERC NOPR noted would be acceptable.
No
As noted in our response to question 2, regulatory approval is often a slow process and is not
conducive to repeating annually. Instead of a 25 MW limit, a 300 MW limit that corresponds to the
reporting level of firm demand in EOP-004 is more appropriate.
FERC order 762 states that "to plan for the loss of firm service at the fringes of various systems would
be an acceptable approach.” The newly defined contingency P2.1 requiring analysis of open ended line
sections should allow load shedding of the load on the line section as suggested in the FERC order.
Individual
John Burnett
Los Angrles Department of Water and Power
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of

customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Individual
Nazra Gladu
Manitoba Hydro
No
The maximum limit ‘x’ MW should vary with system load level and voltage. For example, an ‘x’ MW
interruption would be a very small fraction of a 5000 MW system load level compared to a 1000 MW
load level. Similarly, interruption of ‘x’ MW could be equal to surge impedance loading of a 230 kV
line, where as it would be a fraction of a EHV transmission line loading.
No
A stakeholder process should not be required in jurisdictions where a legislation already authorizes
interruptions, as consent of stakeholders cannot override legislation. If Firm Demand interruptions
require the approval of regulatory authority as described in Section III (for interruptions over 25 MW
or if voltage level of the contingency is greater than 300 kV), the stakeholder process described in
Section I would become a redundant process. Does Section I exclude Firm Demand interruptions
addressed under Section III?
No

1 a. It would be very difficult to estimate the annual hours of exposure at or above a certain load
level. 2 b. An assessment on the health, safety, and welfare of the community should not be part of a
reliability assessment – this is purely subjective. 3 & 4. In situations where load interruption is a new
proposal, historical data will not be available. What does the SDT expect here? 5. Is there a
requirement to mitigate? If there is a requirement to mitigate, the required time frame is not
identified.
No
The Section III states that regulatory authority approval is required for interruptions over 25 MW or if
voltage level of the contingency is greater than 300 kV. However, a regulatory authority cannot
approve interruption of Firm Demand unless it already has such jurisdiction that is conferred upon
them by legislation. A reliability standard cannot confer that jurisdiction. Further, the regulator is
already part of the proposed stakeholder group and will have input into the proposal. The Section III
requires the Regional Entity to review the proposed use of Firm Demand interruption under footnote
‘b’. What impact does it have on the Regional Entity to necessitate a review, if the stakeholders have
already agreed to a process, TPL Reliability Standards performance requirements have been verified
as in Section II.6, and potential overlapping uses have been assessed with adjacent planners as in
Section II.8. What criteria will the Regional Entity use to make their assessment of Adverse Reliability
Impacts and potential cumulative effects given the above TPL performance must be met? This
requirement can lead to inconsistent decisions between regions.
Please clarify if an entity must set up a stakeholder process if Firm demand interruption is not used as
an element of the Corrective Action Plan. As I understand it, the footnote b in TPL 002 will be
replicated in the other relevant TPL standards once it is approved. When it is included in the other TPL
standards, will it be customized to each standard, or will it appear exactly the same in each standard?
Footnote 12 of TPL-001 as currently drafted seems a bit disjointed or incomplete – i.e. its referring to
Non Consequential Load Loss and then it refers you to an Attachment for the calculation of Firm
Demand interruption without providing a connection between the two concepts .
Individual
Test
TEST
Individual
Michael Falvo
Independent Electricity System Operator
No
Specific to the language used in footnote b, we agree with the concept of an approval process for
determining the acceptable level of Firm Demand interruption applicable in a jurisdiction, and do not
agree with prescribing a fixed MW threshold for a continent-wide acceptable Firm Demand
interruption. Therefore, we recommend removing the last sentence in footnote b) which reads “In no
case can the planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW.” and also the same
sentence from Attachement 1 section III. We believe there should not be a fixed limit on the amount
of Firm Demand interruption, for reasons explained below in answers to Questions 4 and 5. As part of
a reliability standard, the footnote should clarify the conditions under which load curtailment will be
allowed, including mention of processes necessary to manage special circumstances. We generally
agree with the reference to Attachment 1, but have concerns about the components of the
Stakeholder Process described in Attachment 1, for reasons described in answers to Questions 2, 3
and 4.
No
(1) The process presented in Section I and the rest of Attachment I is overly prescriptive and lengthy.
As part of a reliability standard, the footnote and process must focus on the impact that Firm Demand
interruption (or Load Rejection) would have on the reliability of the Bulk Electric System and this
aspect is covered in Section III. This Section needs only to stipulate that the proposed utilization of
the footnote be reviewed through (a) an open and transparent stakeholder process and (b) approved
by a relevant reliability authority such as the ERO, Regional Entity or applicable governmental
authority since this authority will eventually need to review, assess and approve the reliability impact
on the interconnected BES of such utilization, with supporting information. Reliability issues and their
assessment and approvals should be dealt with by the applicable reliability authority. Details of other

aspects of Firm Demand interruption, mainly the Stakeholder review and approval process and issues
pertaining to the quality of service, economic and welfare impacts of Firm Demand interruption,
assessment of alternatives (including their economic and welfare impacts), etc. should be dealt with
by the regulatory authority or government body of each jurisdiction (in particular, in non-US
jurisdictions), as is the normal practice for all other Transmission Planning activities. (2) There is no
basis to support allowing the utilization of the footnote in the Near-Term Transmission Planning
Horizon of the Planning Assessment only. The footnote itself leaves the time frame wide open, and
does not explicitly or implicitly restrict its utilization to only the Near-Term horizon. Often, in the longterm planning horizon, when approval for transmission addition or reinforcement cannot be obtained
for whatever reasons, utilization of the footnote is considered and adopted, subject to stakeholders’
and regulatory authorities’ approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year 0ne) time frame and hence the proposed provision does
not allow for utilizing the footnote for the interim period before new or reinforced transmission
facilities are put in place. We suggest removing the word “Near-Term”.
No
Again, this Section is overly prescriptive. This Section needs only to stipulate at a high level, the kind
of information needed to support the proposed utilization of the footnote, leaving much of the detail
to the application process overseen by the applicable reliability authority to review and assess the
reliability impact of such utilization. We suggest the SDT to reduce this Section, or remove this
altogether with appropriate insertion into Section I that address a general need for supporting
information to be specified by the RA’s review process. Also note that use of a “stakeholder process”,
as per FERC’s concerns, must be crisp and clear.
No
We generally agree with the instances for which approvals or interruptions are required. Approval is
to be granted by the Reliability Coordinator or applicable reliability authority. (1) In general, when the
footnote is proposed to be utilized as an interim measure until transmission facilities can be added or
reinforced, regulatory approval must be sought in advance. Having this requirement in a reliability
standard not only is unnecessary, but also introduces regulatory requirements (which provides no
reliability benefit or basis) in a reliability standard. NERC reliability standards should focus only on
BES reliability, not any regulatory requirements. Section III should therefore stipulate a high-level
requirement for the proposing entity to submit the proposal to the Reliability Coordinator for review
and concurrence. The conditions (1) and (2) for seeking explicit regulatory approval can be retained,
but now become the criteria for seeking review and concurrence by the applicable reliability authority.
(2) We suggest deleting Item 1 in the first paragraph (with its a and b bullets) and just indicating that
planned Firm Demand interruption requires approval if it is greater than 25 MW (or other threshold).
Requirements for approval of the use of Firm Demand interruption should be independent of the
voltage level of the contingency. (3) We propose deleting the sentence in the second paragraph “In
no case can the planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW”. A fixed limit on
the allowable size of Firm Demand interruption can not be technically justified for the whole continent
and each case should be assessed to determine if its impact on reliability of the bulk transmission
system is acceptable or not. The impact of each case on the affected customers (economic, welfare,
etc.) will also be reviewed and approved by the regulatory authority or governmental body of each
jurisdiction and a “reliability” standard must not impose limits and restrictions pertaining to these
aspects. (4) The third paragraph proposes that the Regional Entity should review each case of Firm
Demand interruption and verify that there are no Adverse Reliability Impacts. We propose instead
that the transmission planner or planning coordinator study the BES performance requirements and
the reliability impacts of Firm Demand interruption, including its correct operation, miss-operation,
and the failure to operate. The transmission planner should then submit a report of this assessment
to the Reliability Coordinator for review and approval.
(1) We’d like to reiterate our support for allowing load interruption for a single contingency with
sufficient review/oversight and under acceptable conditions, including no adverse impact on the
reliability of the bulk electric system. The reliability aspects (BES performance requirements) should
be reviewed/approved by the Reliability Coordinator. However, issues pertaining to economics or
externalities which may not be directly reliability-related are always available for review and debate
by the stakeholders via the regulatory processes and subject to approval by the regulatory authority
of each jurisdiction (particularly those in Canada and Mexico). (2) Furthermore, we request that Table
1 of TPL-001-3 (previous TPL-001-2 approved by NERC BOT) be corrected for EHV contingencies in

P2, P4 and P5 categories to allow the same load interruption that is allowed for the related P1
contingency. Table 1 currently does not allow any load to be interrupted for an EHV single
contingency if the primary circuit breakers fail to clear the fault (Category P4, “Fault plus stuck
breaker”). But if load X is allowed to be interrupted for a single EHV transmission line contingency
(Category P1), it should be allowed to interrupt the same load X if the primary breaker fails and the
fault is cleared by other breakers. Similarly, if the same breaker has an internal fault or there is a
fault on the same bus section (Category P2) or there is a failure of a relay (Category P5), which
results in the loss of the same EHV transmission line, it should be allowed to interrupt the same load
X. (3) We suggest that NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve them. Accordingly, we believe that the focus of the
foot note ‘b’ should be that interruption of load must not adversely impact the reliability of the
interconnected BES because reliability of supply to load and/or supply continuity is mandated by the
jurisdictional authority. (4) We submit that the scope of NERC’s mandatory standards does not extend
to assessing or setting requirements for non-jurisdictional entities, unless such facilities are necessary
for the operation of the interconnected BES or have an adverse impact on its reliability. For Canadian
entities there are regulatory requirements and processes under the purview of the relevant regulatory
authorities that we believe are adequate. Accordingly, customer interests are protected and are not
subject to unilateral decisions of the transmission planner. In all cases, steps are taken at the
planning, design, and operations stages of system development such that non-consequential Firm
Demand interruption would not adversely impact the BES and the affected customer has been given
the opportunity to avail themselves of other options under the transmission development rules in the
relevant jurisdictions. (5) The requirements of the footnote (including attachment) will amount to a
mandate to construct additional transmission which is inconsistent with Section 215 (i) (2) of the US
Federal Power Act which specifically does not authorize the ERO “to order the construction of
additional generation or transmission capacity or to set and enforce compliance with standards for
adequacy or safety of electric facilities or services. (6) We suggest that NERC should not include
and/or address load reliability or load supply continuity requirements within the BES Reliability
Standards. In Canada, these requirements and approvals are with relevant reliability or regulatory
authority. If NERC feels obligated to include such requirements for load reliability issues in US, then
we propose that non-jurisdictional entities must be exempted from these requirements similar to the
provisions in NUC 001. (7) The proposed implementation plan conflicts with Ontario regulatory
practice respecting the effective date of the standard. It is suggested that this conflict be removed by
appending to the implementation plan wording, after each “applicable regulatory approval” in the
Effective Dates Section A5 of both draft standards, to the following effect: “, or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities.”
Group
Salt River Project
Bob Steiger
ERC
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.

No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do agree with the intent, it is over-reaching for a NERC Standard to require action from the
applicable regulatory authority or governing body responsible for retail electric service issues to give
approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as the
threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As stated
in this questionnaire 25 MW came from registration limit for generation in the ERO Statement of
Compliance Registry Criteria. It will be a stretch to apply this to load.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is admitted for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Individual
Kirit Shah
Ameren
No
We believe that the NERC Glossary contains an adequate definition for Firm Demand, which does not
include Interruptible Demand or Demand-Side Management Load. We do not believe that Interruptible
Demand or Demand-Side Management Load needs to be mentioned in the footnote b) as these types
of Demand are not Firm Demand. Interruptible Demand can be cut at any time and may contain
Demand-Side Management components, and may be direct controlled by the System Operator.
No
We request that Item 1 be modified to include representatives of stakeholders because it may not be
practical to open a meeting to all affected stakeholders. The new sentence of Attachment 1 should
read, “Meetings must be open to all affected stakeholders, or their representatives, including
applicable regulatory authorities or governing bodies responsible for retail electric service issues.”

Also, requirements for a meeting location would sem to eliminate electronic partipation via webex. It
would seem more practical for a TP or PC to host a specific webex to present and discuss the issues
associated with the need to drop Firm Demand. Further, we request that a MW threshold be included
before the Section I stakeholder process would begin, and believe that a minimum threshold of 10
MW of Firm Demand to be cut would be a reasonable value to initiate a stakeholder process. Levels
below 10 MW would be considered as “noise” in the planning horizon. We believe that an approval
should be obtained in the Section I process, which would eliminate the need for Section III. By
requiring an approval of the appropriate local governing bodies responsible for retail service issues
(including rates), there is no need to agree on a cap to limit the amount of Firm Demand dropped.
No
We request that Items 5 and 7 also include information regarding estimated costs and schedule for
implementation. Any permitting issues associated with the alternatives should also be included. Any
previous attempts to build facilities but were blocked should also be part of the record.
No
We do not believe that section III is needed, and particularly if an approval is included as part of the
section I process. We do not subscribe to dropping Firm Demand (non-consequential load) for single
contingency events, and do not see a need to include a voltage threshold as part of the contingency
requirements. All single contingencies in Category B should be applicable.
To clarify, the Stakeholder Process should not be initiated until the amount of Firm Demand expected
to be interrupted by the TP or PC as mitigation reaches a threshold of 10 MW. However, at that point,
the Stakeholder Process should commence, but not without incorporating the need to obtain
approvals from the stakeholders, regardless of the amount of load to be interrupted beyond the 10
MW threshold level, and regardless of the voltage level of the transmission elements involved in the
contingency event(s). As drafted, the Stakeholder Process appears to be silent on receiving approvals
to drop load of less than 25 MW. We believe that this is an invitation to trouble for the industry. For
example, if a TP or PC were to have a contingency for which the mitigation is to interrupt 15 MW of
Firm Demand, all the stakeholders would be called in just to inform them that their load is subject to
interruption, but their displeasure is not relevant, because the 25 MW interruption level had not been
reached, and approval is not required. Thus, we believe that as drafted Stakeholder Process needs
some additional work before we could support it.
Individual
Thad Ness
American Electric Power
Yes
AEP believes it can support the language at this stage, but would like to revisit this after the MW
threshold has been determined.
Yes
Yes
No
AEP is concerned that not all Regional Entities are the same in regards to their engineering and
planning staff, and is not confident that they would all have the resources necessary to perform the
required analysis. AEP is concerned by any attempt to require that a Regional Enity adhere to
processes and prodecures that have not yet been established. FERC has made comments in the past
regarding requirements places upon regional entities (RRO), and while this standard does not yet
apply, is does indirectly obligate them to rules and procedures not yet established.
Individual
John Delucca
LCEC (Lee County Electric Cooperative
“No comment as we have no Firm Demand / Load customers.”

No comment as although we are a Firm Demand customer of another entity, we have no Firm
Demand / Load customers and therefore would not perform the Stakeholder Process
No comment as although we are a Firm Demand customer of another entity, we have no Firm
Demand / Load customers and therefore would not perform the Stakeholder Process
No comment as although we are a Firm Demand customer of another entity, we have no Firm
Demand / Load customers and therefore would not perform the Stakeholder Process
“None”.
Group
MRO NSRF
WILL SMITH
MIDWEST RELIABILITY ORGANIZATION
Yes
The NSRF agrees with the ‘x’ MW statement in footnote b. The NSRF suggests a maximum threshold
value of 300 MW because this is the load loss threshold that the DOE deems to be significant enough
to warrant a NERC system event investigation. To support the inclusion of planning to use up to 300
MW of firm load shedding, registered Transmission Planning entities or regional planning entities
should provide a TPL type analysis that demonstrates the use of planned firm load shedding allows
BES equipment to stay within emergency thermal, voltage, and frequency ranges, and would not
cause instability, uncontrolled separation, and cascading as defined in the FPA Section 215.
No
Order 890 already requires Transmission Planners to solicit the input of affected stakeholders on TPL
standards. Order 890 does not provide prescriptive details regarding the stakeholder process for the
TPL standards, which includes footnote ‘b’. In additions, there is no clear justification to indicate that
the process with regard to footnote ‘b’ warrants more prescription stakeholder process details than
the rest of the TPL standards. So, the NSRF suggests that Section II be removed. If Section I is not
removed, then NSRF suggests at least replacing “all affected stakeholders” with “all known affected
stakeholders” or “appropriate known affected stakeholders” because an entity can develop a list of all
known affected entities for compliance purposes and document that the meeting was open to them
and that they were notified. An entity cannot demonstrate that a stakeholder meeting is open to
unknown stakeholders or that it notified unknown stakeholders. The use of “all” in mandatory zero
defect standards is not appropriate in NERC standards, especially when potential large diverse
populations such as affected stakeholders must be considered.
No
Order 890 already requires Transmission Planners to solicit the input of affected stakeholders on TPL
standards. Order 890 does not provide prescriptive details regarding the information that should be
included in the stakeholder process for the TPL standards, which includes footnote ‘b’. Stakeholders
that participate in stakeholder meeting can ask for any information that they want regarding the
proposed use of Firm Demand interruption. They do not need a third party to prescribe what
information they need or want. So, the NSRF suggests that Section II be removed. If Section II is not
removed, then the NSRF suggests that at least Items 2b, 6, and 8 be removed from the listing. •
Item 2b – The scope and content expectation for an assessment of the potential impact of the
proposed Firm Demand interruption on the health, safety, and welfare of the community is basically
broad, nebulous, and vague. The stakeholders would raise any specific, relevant questions or
concerns in these areas if they exist without a prescriptive stipulation for this information in the TPL002 standard. • Item 6 – The verification of that the TPL performance requirements will be met by the
use of Firm Demand interruption is superfluous. Proposal to use Firm Demand interruption to meet
the TPL-002 performance requirements would always be the result of identifying (i.e. verifying) what
Firm Demand interruption is needed to meet the TPL-002 performance requirements. • Item 8 –
Potential overlapping uses of footnot ‘b’ with adjacent planners will not always exist and would
probably be rare. In addition, whenever the situation would exist, then any applicable adjacent
planners would be affected stakeholders and would have the opportunity to attend the stakeholder
meeting and raise any questions or concerns in that meeting without the stipulation of this
information in the TPL-002 standard.
No
The NSRF suggests that Section III be removed for the following reasons. • The types of transmission

projects that would be needed to avoid proposing the use of the Firm Demand interruption under
footnote ‘b’ are expected to be high cost, long lead time Corrective Action projects. Therefore,
consideration of the any necessary approvals from regulatory authorities or governing bodies
responsible for approving the Corrective Action project is a prerequisite and essential to any
discussion or stiputlations regarding disapproval of the use of footnote ‘b’ proposal. The proposed
TPL-002 text for Section III does not include any language to address this crucial aspect of any
footnote ‘b’ approval sipulations. • The diversity of applicable regulatory authorities and governing
bodies, as well as their justicitional scope or criteria with respect to the approval of interrupt retail
electic service (as well as transmission Corrective Action projects), are too diverse and complex to be
appropriately addressed by proposed Approval stipulations in the TPL-002 standard. If Section III is
not removed, then the NSRF suggests the following changes. • Include the subject of approvals of
Corrective Action projects that are necessary to negate the need for approval of the proposed Firm
Demand interruption. • Replace the criteria regarding the voltage level of the relevant Contingency
with criteria regarding the amount and type of Firm Demand that would be subject to interruption.
The voltage level of the applicable Contingency elements are not material to impact on the affected
load. • Replace the applicable amount of Firm Demand interruption criteria from 25 MW to at least
100 MW. There are many radial fed loads that are much geater that 25 MW and there are no
stackholder meetings and required approvals for allowing the loads to be fedd radially (subject to
interruption for Category B contingencies) rather than being network fed. The DOE threshold for
requiring formal system event analysis is 100 MW of load dropping. So, why should the TPL-002
standard required special approvals to allow less than 100 MW of load be subject to interruption to
assure BES reliability? • Change the text of “in Year One of the Planning Assessment” to “in the ten
year planning horizon of the Plannign Assessment”. The planning assessments may reveal that the
need to use of Firm Demand interruption will occur in Year 2, Year 3 or beyond (e.g. when a
significant previously unforecast load increase is forecast to occur before any needed Corrective
Action project could be initiated and implemented). • The NSRF is concerned that the current
wording, “Corrective Action in Year One of the Planning Assessment” could be interpreted to require
an annual stakeholder process review and approval. The NSRF suggests that the standard drafting
team provide some language regarding a specific period that is expected for reaffiming the approval
of the Firm Demand interruption. A review interval of at least every five years should provide
reasonable business certainty and allow for future transmission construction if needed. The specific
defined period of review should allow entities to operate in an effective manner. The NSRF is also
concerned about the condition where approval was granted and then removed. Would an entity be
instantly non-compliant to the TPL standards? If this is a possibility, the Standard Drafting Team
should add a grace period that allows an entity to credibly construct a project to remain compliant.
The NSRF has concerns that over regulation of footnote “b” or “12” could cause lost opportunities for
legitimate growth. An example condition would be the development of a large load in a relatively
weak transmission area. Many times new large loads need open undeveloped areas to locate. Without
the footnote “b” or “12” option, could an entity be forced to turn away legitimate load growth? The
key being that an entity could serve the new large load under normal conditions with easy quick
upgrades, but would need 5 – 7 years to construct additional transmission to meet N-1 conditions?
Therefore the entity would need to turn away new growth because of over regulation on footnote “b”
or “12”.
Individual
Andrew Z. Pusztai
American Transmission Company
No
ATC agrees with the ‘x’ MW statement in footnote ‘b’ , however, supports a maximum threshold value
of 300 MW because this is the load loss threshold that the DOE deems to be significant enough to
warrant a NERC system event investigation.
No
Order 890 already requires Transmission Planners to solicit the input of affected stakeholders on TPL
standards. Order 890 does not provide prescriptive details regarding the stakeholder process for the
TPL standards, which includes footnote ‘b’. In addition, there is no clear justification to indicate that
the process with regard to footnote ‘b’ warrants a more prescriptive stakeholder process than the rest
of the TPL standards. So, ATC recommends that Section I be removed. If Section I is not removed,

then ATC suggests replacing “all affected stakeholders” with “all known affected stakeholders”
because an entity can develop a list of all known affected entities for compliance purposes and
document that the meeting was open to them and that they were notified. An entity cannot
demonstrate that a stakeholder meeting is open to unknown stakeholders or that it notified unknown
stakeholders. The use of “all” in mandatory zero defect standards is not a good practice, especially
when large diverse populations of affected stakeholders are considered.
No
Order 890 already requires Transmission Planners to solicit the input of affected stakeholders on TPL
standards. Order 890 does not provide prescriptive details regarding the information that should be
included in the stakeholder process for the TPL standards, which includes footnote ‘b’. Stakeholders
that participate in stakeholder meetings can ask for any information they want regarding the
proposed use of Firm Demand interruption. Therefore, ATC recommends that Section II be removed.
If Section II is not removed, then ATC recommends that Items 2b, 6, and 8 be removed from the
listing. • Item 2b – The scope and content expectation for an assessment of the potential impact of
the proposed Firm Demand interruption on the health, safety, and welfare of the community is broad,
nebulous, and vague. The stakeholders would raise any specific, relevant questions or concerns in
these areas if they exist without a prescriptive stipulation for this information in the TPL-002
standard. • Item 6 – The verification that the TPL performance requirements will be met by the use of
Firm Demand interruption is superfluous. Proposal to use Firm Demand interruption to meet the TPL002 performance requirements would always be the result of identifying (i.e. verifying) what Firm
Demand interruption is needed to meet the TPL-002 performance requirements. • Item 8 – Potential
overlapping uses of footnote ‘b’ with adjacent planners will not always exist and would probably be
rare. In addition, whenever the situation would exist, any applicable adjacent planners would be
affected stakeholders and would have the opportunity to attend the stakeholder meeting and raise
any questions or concerns in that meeting without the stipulation of this information in the TPL-002
standard.
No
ATC recommends that Section III be removed for the following reasons. • The types of transmission
projects that would be needed to avoid proposing the use of the Firm Demand interruption under
footnote ‘b’ are expected to be high cost, long lead time Corrective Action projects. Therefore,
consideration of the any necessary approvals from regulatory authorities or governing bodies
responsible for approving the Corrective Action project is a prerequisite and essential to any
discussion or stipulations regarding disapproval of the use of footnote ‘b’ proposal. The proposed TPL002 text for Section III does not include any language to address this crucial aspect of any footnote
‘b’ approval stipulations. • The diversity of applicable regulatory authorities and governing bodies, as
well as their jurisdictional scope or criteria with respect to the approval of interrupt retail electric
service (as well as transmission Corrective Action projects), are too diverse and complex to be
appropriately addressed by proposed approval stipulations in the TPL-002 standard. If Section III is
not removed, then ATC recommends the following changes. • Include the subject of approvals of
Corrective Action projects that are necessary to negate the need for approval of the proposed Firm
Demand interruption. • Replace the criteria regarding the voltage level of the relevant Contingency
with criteria regarding the amount and type of Firm Demand that would be subject to interruption.
The voltage level of the applicable Contingency elements are not material to impact on the affected
load. • Replace the applicable amount of Firm Demand interruption criteria from 25 MW to at least
100 MW. There are many radially fed loads that are much greater than 25 MW and there are no
stakeholder meetings or required approvals for allowing the loads to be fed radially. The DOE
threshold for requiring formal system event analysis is 100 MW. So, ATC believes the TPL-002
standard should not require special approvals to allow less than 100 MW of load to be interrupted to
assure BES reliability. • Change the text of “in Year One of the Planning Assessment” to “in the ten
year planning horizon of the Planning Assessment”. The planning assessments may reveal that the
need to use of Firm Demand interruption will occur in Year 2, Year 3 or beyond (e.g. when a
significant previously unexpected load increase is forecast to occur before any needed Corrective
Action project could be initiated and implemented). • ATC is concerned that the current wording,
“Corrective Action in Year One of the Planning Assessment” could be interpreted to require an annual
stakeholder process review and approval. ATC suggests that the standard drafting team provide some
language regarding a specific period that is expected for reaffirming the approval of the Firm Demand
interruption. A review interval of at least every five years should provide reasonable business

certainty and allow for future transmission construction if needed. The specific defined period of
review should allow entities to operate in an effective manner.
Individual
James Tucker
Deseret Generation & Transmission Cooperative
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.

: The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Individual
Brian Keel
Salt River Project
No
Additional comment from SRP for Q #5.
No
Additional comment from SRP for Q #5.
No
Additional comment from SRP for Q #5.
No
Additional comment from SRP for Q #5.
The new definition of Non-consequential Load Loss compared to the last version seems to have
deleted the reference to Loads that may be lost during transient conditions due to under-frequency
load shedding (UFLS), while the reference to Load Loss due to under-voltage load shedding (UVLS) is
retained. As a result Load Loss due to UFLS would be part of Non-consequential Load Loss, and will
not be allowed under single contingency. Because UFLS may also be triggered during transient
simulations, please change the definition for Non-consequential Load Loss to read: “NonConsequential Load Loss: Non-Interruptible Load loss that does not include: (1) Consequential Load
Loss, (2) the response of voltage sensitive Load or frequency sensitive Load, or (3) Load that is
disconnected from the System by end-user equipment.” It is also understood that load loss due to
UVLS or UFLS or load that are disconnected from the system by customer equipment are not to be
used in meeting steady state reliability requirements. Therefore, in Table 1, please change headernote “i” to read: “The response of voltage sensitive Load and Frequency 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.”
Individual
Andrew Gallo
City of Austin dba Austin Energy
Yes
Yes
No
Some of the information for inclusion in the Stakeholder Process is too burdensome and of limited
value. In particular, 2b and 4 can be deleted because the requested information may not be available
-- particularly if it is new load growth.

No
The 25 MW threshold for Approval of Interruptions of Firm Demand under Footnote ‘b’ is too low. It
should be increased to 50 MW because there is an elaborate Stakeholder process to work through the
reliability concerns.
Individual
Anthony Jablonski
ReliabilityFirst

No
ReliabilityFirst has a major issue/concern with Attachment 1, Section 3 (specifically the last paragraph
regarding approval). This section requires the Regional Entity to review each proposed use of Firm
Demand interruption under footnote 12 in order to verify that there are no Adverse Reliability
Impacts. The paragraph goes on to require the Regional Entity to make its determinations and
evaluation of Adverse Reliability Impacts using a published methodology approved by the ERO. First,
since the Regional Entity is not a user, owner or operator of the BES, ReliabilityFirst believes the
Regional Entity should not have requirements placed upon them. Furthermore there is no guidance on
what is required to be placed within the published methodology. ReliabilityFirst believes this
verification is outside the Regional Entity scope as delegated by the ERO. ReliabilityFirst believes that
if such verification by the Regional Entity is required, it should be specifically laid out in the NERC
Rules of Procedure and not an attachment within a standard.
Group
SERC EC Planning Standards Subcommittee
Jim Kelley
PowerSouth Energy Cooperative
No
We do not agree with this approach since there is no technical basis for allowing load shedding. It is
all an administrative process which could result in inconsistencies from area to area. If a single
contingency results in a local network becoming temporarily radial, then load shedding within the
local network should be allowed. A limitation of up to some maximum amount of load shedding (to be
determined) should be imposed. This would provide a technical basis for load shedding, which would
help ensure consistency.
No
We recommend using a technical basis for load shedding instead of a Stakeholder Process.
No
We recommend using a technical basis for load shedding instead of a Stakeholder Process.
No
We recommend using a technical basis for load shedding instead of a Stakeholder Process. However,
if a Stakeholder Process is used, the approval thresholds are correct. The Stakeholder Process should
not even be initiated for less than these threshold levels.
The comments expressed herein represent a consensus of the views of the above-named members of
the SERC EC Planning Standards Subcommittee only and should not be construed as the position of
SERC Reliability Corporation, its board, or its officers.
Individual
Kayleigh Wilkerson
Lincoln Electric System
No
LES suggests the following changes to Footnote B/12 to further clarify the drafting team’s intent.
Under Footnote B/12, recommend the first sentence be modified to state “An objective of the planning

process is to minimize the likelihood and magnitude of interruption…”. Additionally, please clarify the
reference to the Near-Term Transmission Planning Horizon while remaining silent on the Long-Term
Transmission Planning Horizon. Does Appendix 1 apply to the Long-Term Transmission Planning
Horizon as well as the Near-Term Transmission Planning Horizon?
Yes
Although LES agrees in general with the description and components included as part of Section I, we
suggest the following wording changes to enhance Section I. Recommend the drafting team delete
item 2(c) as it is duplicative of item 4 which is more succinctly worded. Also, recommend additional
wording be added to the end of item 3 to provide meeting participants with advanced notice of the
information. As an example, “information…must be made available to meeting participants [ten days
prior to the meeting].”
Yes
No
For item 1(b) in Section III, LES requests that the drafting team clarify why approval by the
regulatory authority for a generator contingency is based on the high-side voltage of the GSU rather
than the generator capacity. LES believes the generator capacity, rather than the high-side voltage of
the GSU, provides a more consistent basis for determining necessity for approval from the applicable
regulatory authority or governing body. Additionally, LES asks for further clarification as to whether
the steps referenced for Year One of the Planning Assessment extend to Year Two and beyond.
Individual
Milorad Papic
Idaho Power Co.
Yes
Maximum threshold for Planned Firm Demand interruption should be based on a previous year
recorded peak demand. For instance for recorded peak demand of more than 3,000 MW the
maximum treshold should be greater than 300 MW.
Yes
Yes
Yes

Individual
Martyn Turner`
LCRA Transmission Services Corporation
No
Footnote 12 is applied in column labeled “Non-Consequential Load Loss Allowed.” However, the last
sentence of the proposed Footnote 12 switches from using the terms Consequential Load Loss and
Non-Consequential Load Loss to using the term “Firm Demand.” The term “Firm Demand” should be
revised to “non-Consequential Load Load loss.” In addition, the application of Footnote 12 to the P3
contingency category should be removed.
No
In the Proposed Revision to the Standard, Footnote 12 is applicable to the use of Non-Consequential
Load Loss to relieve criteria violations resulting from P1, P2, and P3 category contingencies, however,
Footnote 12 and Attachment I switch terms and begins using “Firm Demand.” Though it may be
reasonable to characterize Non-Consequential Load Loss as a subset of Firm Demand not all Firm
Demand is Non-Consequential Load Loss. The term “Firm Demand” as used in Footnote 12 and
Attachment I should be replaced with “Non-Consequential Load Loss.” Application of the term “Firm
Demand” in Footnote 12 and Attachement 1 introduces an ecomonic criteria to the TPL-001 Reliability
Standard. For intstance, the interruption of “Firm Demand” as defined in the NERC Glossary may not

require Non-Consequential Load Loss, however, this is an economic decision between the parties
involved in the Firm Demand contract. In addition, a Transmission Planner or Tranmission Owner may
or may not be a party to the Firm Demand contract. The process outlined in Attachment 1 applies to
the P3 contingency category (through the application of Foontote 12) and thus represents a
significant and substantive change in the reliability standard over previous standards. The reference
to Footnote 12 should be deleted from the P3 contingency category.
No
Requirement 1 only requires that the Transmission Planner provide system load data, however,
assumptions about system dispatch are also relevant. Requiring load without dispatch will not provide
a complete understanding of the conditions under which Footnote 12 will apply. As a reliability
standard, the Transmission Planner is required to find a range of plausible system conditions under
which a criteria violation may be resolved. The requirement (1a) to provide an estimate of the
exposure creates an overly burdensome requirement to investigate a wider range of possible
operating conditions than is currently performed. Requirement 2a and 2b are overly burdensome on
at Transmission Planner/Transmission Owner who does not directly serve retail loads by placing a
requirement on the Transmission Planner/Transmission Owner to provide data that is outside of its
control to develop or maintain.
No
See previous comments about use of the term “Firm Demand”.
The primary objection to Footnote 12 is twofold: 1. Application to the P3 contingency. This
contingency is a Category C contingency under the current NERC TPL-003 standard and allows for
load shedding. Thus, the proposed standard revision is a significant and substantial increase in the
reliability standard. 2. Use of the term “Firm Demand” as opposed to “Non-Consequential Load Loss.”
The NERC Glossary defines Firm Demand as “That portion of the Demand that a power supplier is
obligated to provide except when system reliability is threatened or during emergency conditions” and
Demand as “The rate at which electric energy is delivered to or by a system or part of a system,
generally expressed in kilowatts or megawatts, at a given instant or averaged over any designated
interval of time.” Thus interruption of Firm Demand may not result in Non-Consequential Load Loss.
Therm “Firm Demand” should be replaces with “Non-Consequential Load Loss.”
Group
Southern Company
Antonio Grayson
Operations Compliance
No
Southern does not agree with this Stakeholder Process approach since there is no technical basis for
allowing load shedding. It is all an administrative process which could result in inconsistencies from
area to area. A more technical based approach was the one taken by the SDT in an earlier draft temporarily radial concept. If a single contingency (Category B) results in a local network becoming
temporarily radial, then load shedding within the local network should be allowed since it would not
have any impact to the reliability of the transmission grid. A limitation of up to some maximum
amount ('x' MW) of load shedding (to be determined) should be imposed. This would provide a
technical basis for load shedding, which would help ensure consistency from area to area.
Furthermore, this would provide a method for defining the "fringes" of the power system.
No
Southern recommends using a technical basis for load shedding (see comment in Question 1 above)
instead of a Stakeholder Process.
No
Southern recommends using a technical basis for load shedding instead of a Stakeholder Process.
No
Southern recommends using a technical basis for load shedding instead of a Stakeholder Process.
However, if a Stakeholder Process is used, the approval thresholds given in the draft seem
appropriate. Furthermore, we believe the Stakeholder Process should not even be initiated for less
than these threshold levels. Lower amounts of load and lower voltage contingencies do not need to be
taken through a Stakeholder Process.

The use of load dropping should be limited to being only an interim solution while a project is being
completed and nothing else can be done.
Individual
Jonathan Fidrych
Tri-State Generation & Transmission Association, Inc.
No
There are several points that we disagree with in terms of the Stakeholder Process in the body of the
footnote. First, the footnotes are not written in a manner so as to clearly be only applicable to
Planning Standards. Many parts of the footnotes and the Attachment I can be misconstrued as
Operational requirements. For example, the sentence that states “Curtailment of firm transfer…”
should state “Planned curtailment of firm transfer…” Second, we disagree with the imposition of a
maximum limit on the amount of planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences on service reliability. We
suggest removal of this sentence. Assigning a fixed “not to exceed” number of MW in a continentwide standard is overly prescriptive. A single number cannot account for variation even within one BA
Area. This number will be too high for some planning systems and too low for others. A fixed
maximum number of MW for Non-Consequential Load Loss under Footnote b in TPL-002 (and footnote
12 in TPL-001-3) is not necessary. The first sentence of this footnote states, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events”. It is clear that the spirit of the TPL Standard is to
minimize the likelihood and magnitude of Firm Demand interruption. Adding a fixed maximum
number of MW would seem unnecessary at best. At worst, it could have unintended consequences.
Without a fixed maximum Non-Consequential Load Loss, the Transmission Planner understands that
the objective is to minimize the magnitude of the planned interruption under footnote b (TPL-001-3,
footnote 12). Lastly, in an effort to develop a clearer and more transparent compliance standard, it is
recommended that the additional requirements imposed by this footnote be broken into separate
requirements set forth within the body of the standard itself. Do not imbed requirements in footnotes.
No
We disagree with Section I of Attachment I to the extent that there currently are several other venues
through which stakeholder input is mandated. In addition, we do not believe NERC Reliability
Standards have the authority to dictate stakeholder outreach processes. For several reasons,
including the time required for public input, permitting, acquisition, and construction, most
transmission projects take several years to build. TPs will develop plans to mitigate BES performance
violations, but those plans may not be able to be constructed in time. The Footnotes do not allow
planners to design temporary mitigation to accommodate real world construction issues, which are
often complex in nature due to competing interests.
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
We disagree with the instances for which Approval of Interruptions is required as proposed by Section
III of Attachment I. TPs will develop plans to mitigate BES performance violations, but those plans
may not be able to be constructed in time. The reason being that the time required to construct a
project to mitigate the issues can take several years. This is due to the need for public input,
permitting, acquisition, and construction. Attachment I does not allow planners to design temporary
mitigation to accommodate real world construction issues, which are often complex in nature due to
competing interests. Attachment I also states that “Before a Firm Demand interruption under footnote
‘b’ is allowed to be utilized as an element of a Corrective Action Plan in Year One of the Planning
Assessment…” The need for approval seems burdensome such that it does not allow for temporary
mitigation to meet BES performance criterion while other avenues are explored and vetted. The intent

of Section III is genuine, but we feel that it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Group
Arizona Public Service Company
Janet Smith
Arizona Public Service Company
Yes
Yes
Yes
No
AZPS does not agree that approval by the Regional Entity should be required. Once the process has
been fully vetted by the stakeholders, including the regulatory authority for retail service, there is
absolutely no need for Regional Entity approval. There would be no adverse affect of nonconsequential load tripping on the BES. No reason for Reginal Entity involvement.
This process is too prescriptive and must be simplified.
Individual
John Martinsen
Public Utility District No. 1 of Snohomish County
No
No
No
No
Comments: SNPD generally disagrees with the draft process that has been developed, and notes that
infrequent interruption of small amounts of non-consequential load under limited conditions that does

not negatively impact a neighboring TOP is not a reliability issue. Instead it is a cost of service and
customer service matter best left to the local and state regulatory bodies. The time and resources
spent on this issue at the national level diverts scarse resources and attention from more important
efforts that might actually benefit the reliability of the BES. SNPD supports the Pacificorp Revision of
TPL-002 footnote ‘b’ and TPL-001 footnote 1 Comments- The proposed revisions will require
regulatory approval for interruptions of firm demand under TPL-002 footnote b or TPL-001 footnote
12 if the voltage level of the contingency is greater than 300 kV with certain sub-conditions or if the
planned interruption of firm demand under these footnotes is greater than or equal to 25 MW. The
2011 peak winter and summer loads in the Western Electricity Coordinating Council (WECC) region
were 131,471 and 152,211 MW respectively. Total installed generation is 229,189 MW. There are
120,385 miles of AC transmission lines 100 kV and above, and of that total, 31,138 miles of AC
transmission lines are operated at voltages above 300 kV. There are 1,744 miles of DC transmission
lines. The proposed revisions would add considerable process and documentation for any
interruptions, and will require regulatory approval if the interruption is greater than 25 MW. This is
0.016 percent of the WECC peak load. The planning standards already require Category B1
contingencies to be considered which result in the loss of a single generator since individual generator
units range in size up to more than 1000 MW. Since these contingencies are routinely studied, it is
very, very difficult to imagine that the loss of 25 MW or more of firm demand under TPL-002 footnote
b or TPL-001 footnote 12 is so critical to the reliability of the BES that it deserves not only a lengthy
footnote, but a two page attachment detailing a complex and lengthy process detailing requirements
public meetings, procedures for questions, specifications for documentation, and even a dispute
resolution process. As this is not a BES reliability issue, any action regarding potential curtailments of
local loads should occur at the local level where the cost and benefit of improvements can be properly
assessed. The recent blackout that left 2.7 million customers in Southern California, Arizona and Baja
California without power was not due to planned or controlled interruption of electric supply where a
single contingency occurs on a transmission system. SNPD is not aware of any regional disturbances
or cascading events that were due to planned or controlled interruptions of electric supply where a
single contingency occurred on a transmission system. As these proposed requirements could be
removed from the Reliability Standards with little or no effect on reliability and would, if anything,
increase the efficiency of the ERO compliance program, the proposed limitations on curtailment of
firm demand under TPL-002 footnote b or TPL-001 footnote 12 should be removed.
Individual
Robert W. Creighton
Nova Scotia Power
Yes
Yes
Yes
Yes
With regard to the application of Footnote 12 in TPL-001-3, the footnote is only applied to the
contingencies in Table 1 involving loss of a Single Line with a 3 phase fault (P1) or opening of a line
without a fault (P2-1). These are higher probability events relative to other types of contingencies,
and Footnote 12 allows for loss of load for these events, but does not allow for loss of load for lower
probability events that have the same results, such as P2-2 and P2-3. Take for example a single
radial 345kV line feeding a small radial portion of the system, with a line end transformer and breaker
between the transformer and the line. Application of Footnote 12 to only a P1 event (loss of the line
on its own, or loss of the transformer on its own) but loss of the breaker between the line and the
transformer would not be allowed, even though the result would be the same. Without applying
footnote 12 to category P2-2 and P2-3 would mean that Footnote 12 is rendered moot (can never be
used). Similarly, Footnote 12 should be applied to P4 and P5, essentially wherever Footnote 9 is
applied, otherwise Footnote 12 can never be applied.
Individual

Greg Rowland
Duke Energy
Yes
Situations where use of footnote ‘b’ would be appropriate can’t be readily characterized with criteria
leading to some “technically justified” maximum capacity threshold for interruption. That being the
case, a maximum capacity threshold could be established based upon other criteria, such as the 300
megawatt threshold for DOE disturbance reporting.
No
Since item 2 describes the public notice that must be provided, the phrasing of 2.b should be revised
to replace the words “Specific applications” with the words “Summary description”. “Specific
applications” could be considered to require detailed descriptions of each and every contingency that
could lead to use of footnote ’b’. That level of detail could certainly be provided to meeting
participants, but shouldn’t be necessary for the public notice.
No
In Item #8, replace the word “planners” with the words “Transmission Planners”.
No
Section III is confusing. Are the last two paragraphs of Attachment 1 supposed to be part of Section
III? These paragraphs, when read in combination with the first paragraph of Attachment 1, seem to
say that any time a Firm Demand interruption using footnote ‘b’ or footnote 12 shows up in the NearTerm Transmission Planning Horizon, the Stakeholder Process must be invoked. It would seem more
reasonable to invoke the Stakeholder Process only when such interruption occurs in Year One of the
Planning Assessment.
Individual
Chris de Graffenried
Consolidate Edison Co. of NY, Inc.
No
See reply to Question 5
No
See reply to Question 5
No
See reply to Question 5
No
See reply to Question 5
Planned interruptions of Firm Demand in response to a Single Contingency (as directed in Footnote b
of TPL-002 Table 1, is not an acceptable corrective action to mitigate reliability issues on the BES
system. The Interconnected System should be designed and operated with enough transfer capacity
to be able to withstand, at a minimum, a single contingency event without service interruptions to
customer load. Systems must be designed and operated so that the impact of any single contingency
can be mitigated by re-dispatching available system resources without the need to implement load
shedding.
Individual
Charlie Pottey
Sierra Pacific Power Co d/b/a NV Energy
Individual
Richard Vine
California Independent System Operator
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number

cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount. We support the
description and components of the Stakeholder Process in the body of the footnote, but do not agree
with the imposition of a maximum limit on the amount of planned Firm Demand interruption under
footnote b. This addition is overly prescriptive, unnecessary, and can have unintended consequences
on service reliability, as explained above. Also, we have comments on the reference to Attachment I.
Please see our comments under Q5.
No
The process presented in Section I of Attachment I is overly prescriptive. Identifying the need for
stakeholder consultation on this issue within the consultation process already employed by the
Transmission Planner or Planning Coordinator should be sufficient detail. In particular, however, we
suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution? There is
no basis to support only allowing the utilization of the footnote in the Near-Term Transmission
Planning Horizon of the Planning Assessment. The footnote itself leaves the time frame wide open,
and does not explicitly or implicitly restrict its utilization to only the Near-Term horizon. Often, in the
long-term planning horizon, when approval for transmission addition or reinforcement cannot be
obtained for whatever reasons, utilization of the footnote is considered. Note that it is impractical to
add or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame and hence
the proposed provision does not allow for utilizing the footnote for the interim period before new or
reinforced transmission facilities are put in place. We suggest removing the word “Near-Term”.
No
This Section is overly prescriptive. This Section needs only to stipulate at a high level, the kind of
information needed to support the proposed utilization of footnote b and footnote 12. In particular, we
disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
We do not agree with the requirement to seek regulatory authority approval or Regional Entity
approval. Having this requirement in a reliability standard not only is unnecessary, but also introduces
regulatory requirements (which provide no reliability benefit or basis) in a reliability standard. NERC
reliability standards should focus only on BES reliability, not on any regulatory requirements. A
notification process should be sufficient. It is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
for approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As

stated in this questionnaire, 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It would be a stretch to apply this to load. Requiring the Regional
Entity to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL001-3) would be duplicative and would increase the work load of the Regional Entities without
improving reliability. The TP and PC are already required to make available to the affected
stakeholders, verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’ (see Section II.6) and the assessment of potential overlapping
uses of footnote ‘b’ with adjacent planners” (see Section II.8). What type of review and verification
would be required to show that “there are no Adverse Reliability Impacts including any potential
cumulative effect within the Regional Entity’s footprint”?
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column. The
process described in Attachment 1 may be more suited for inclusion in the Rules of Procedure, similar
to the process required for seeking BES facility exceptions. We urge the SDT to consider moving
Attachment 1 into a proposed RoP instead of stipulating it in the standard.
Individual
charlie pottey
nevada power company dba nvenergy
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many

affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Group
Western Area Power Administration
Brandy A. Dunn
Western Area Power Administration (Corp. Services Office)
No
The addition of the "Stakeholder Process" outlines in Attachment 1 is so onerous so as to persuade
entities NOT to attempt the use of Footnote b) OR 12). Is this the intent?

Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
Comments: It is difficult to establish the maximum value for acceptable Firm Demand interruption.
For example, an entity may have an acceptable maximum load loss to avoid impacts on the grid such
as generation trip-outs. For Hydro-Québec TransÉnergie (HQT), in the Québec Interconnection, this
value is above 1,000 MW. No maximum value should be posted in Footnotes 12 and ‘b’, since it is
specifically related to system design and Interconnection size (inertia). Let us keep in mind that the
goal of the TPL standards is not service continuity of local loads but global reliability of the system.
Even though service continuity is important, TPL standards should not address this issue by posting a
maximum allowable load loss. Moreover, HQT considers that a Stakeholder Process such as seen in
Attachment I has no place in a standard and its footnotes. Mainly, the Stakeholder Process doesn’t
consider that entities may have their own regulatory authorities with different processes, which do not
specifically establish this load loss value.
No
The Stakeholder Process doesn’t consider that entities may have their own regulatory authorities with
different processes, which do not specifically establish load loss values. Also, the use of Firm Demand
interruption in the Corrective Plan should not be limited only to the Near-Term Transmission Planning
Horizon. It should also be allowed for the Long-Term horizon, at least for Multiple Contingencies.
No
For example, under 2 b., assessment of the impacts of interruptions on health, safety, or welfare of
the community is not information that could be reasonably expected to be available to system
planners. All loads may face interruptions from time to time, and the impact on health, safety or
welfare is very difficult to identify. This item should be deleted.
No
For example, in 1a., it is not clear what is meant by "the stated performance criteria regarding
allowances…". Why is it necessary to give this kind of explanation? In 1b., the use of the term "nongenerator step up transformer" is unusual. Suggest rewording 1b to read: For a generator or
generator step up transformer outage Contingency, the extra high voltage (EHV) limit applies to the
BES connected voltage (high-side of the Generator Step Up transformer). For any other transformer
outage Contingency, the EHV limit applies to the low-side winding (excluding tertiary windings).
Footnote 12 is not applied to Categories P4 and P5, which would include a EHV stuck breaker or
failure of a non-redundant relay for a Multiple Contingency. The Load loss restriction for the
contingencies listed in P4 and P5 is more restrictive than for the loss of a EHV double circuit line.
Statistics indicate that the contingencies presented in P4 and P5 are less frequent. HQT requests that
Footnote 12 should also be used for P4 and P5 contingencies for EHV. Even though considering Firm
Demand interruption in planning might not be common practice, HQT agrees that the proposed
Footnote 12 should maintain such a possibility.
Individual
Chris Scanlon
Exelon
No
For TPL-001, the wording for footnote 12 does not make clear that DSM would be allowed without the
Attachment 1 procedure. ComEd suggests the following wording change: 12. An objective of the
planning process should be to minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency events. However, in limited circumstances Non-Consequential Load Loss may
be needed to ensure that BES performance requirements are met. When Non-Consequential Load
Loss is utilized within the planning process to address BES performance requirements (other than
Interruptible or Demand Side Management load), such interruption is limited to circumstances where
the Non-Consequential Load Loss is meets the conditions shown in Attachment 1. In no case can the
planned Firm Demand interruption under footnote 12 exceed ‘x’ MW. For TPL-002, the wording of

footnote “b” is not totally clear that it applies only to non-consequential load shed and not
consequential load shed. ComEd suggests that the wording of footnote “b” be changed as shown: b)
An objective of the planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency events. Curtailment of firm
transfers is allowed when achieved through the appropriate re-dispatch of resources obligated to redispatch, 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2)
Interruptible Demand or Demand-Side Management Load. Furthermore, in limited circumstances Firm
Demand may need to be interrupted to ensure that BES performance requirements are met. When
interruption of Firm Demand (other than in (1) or (2) above) is utilized within the planning process to
address BES performance requirements, such interruption is limited to circumstances where the use
of Firm Demand interruption meets the conditions shown in Attachment 1. In no case can the planned
Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW.

Individual
Catherine Mathews
NorthWestern Energy (NWMT)
No
Comments: A fixed maximum number of MW for Non-Consequential Load Loss should not be used in
an industry-wide standard. There is too much diversity. We suggest that a fixed maximum number
not be stipulated.
No
Comments: It is unclear how the dispute resolution process would treat stakeholders with different
concerns. We suggest that Item 5 of Attachment 1 be deleted.
No
Comments: The estimated number and type of customers affected is not needed for reliability of the
Bulk Power System. We suggest removing Item 2a in Section II of Attachment 1. An assessment of
the health, safety, and welfare of the community should not be required. It is too vague and coud
present legal problems. We suggest removing Item 2b in Section II of Attachment 1.
No
Comments: A NERC Standard should not require action from a regulatory authority to approve the
use of Firm Demand interruption. There is too much diversity in regulatory authorities over the
industry-wide area. This would increase the work load of the Regional Entities without improving
reliability. We suggest removing Section III of Attachment 1.
Comments: Footnote 12 should be added to Category P2 Single Contingency Event 2, Bus Section
Fault, and to Category P2 Single Continency Event 3, Internal Breaker Fault , for EHV in the NonConsequential Load Loss column.
Individual
Robert Casey
Georgia Transmission Corporation
Yes
Please remove the “is” as shown below: “12. An objective of the planning process should be to
minimize the likelihood and magnitude of Non-Consequential Load Loss following Contingency events.
However, in limited circumstances Non-Consequential Load Loss may be needed to ensure that BES
performance requirements are met. When Non-Consequential Load Loss is utilized within the planning
process to address BES performance requirements, such interruption is limited to circumstances
where the Non-Consequential Load Loss [IS] meets the conditions shown in Attachment 1. In no case
can the planned Firm Demand interruption under footnote 12 exceed ‘x’ MW.”

No
Item #1 in Section I should be reworded: From This....“Meetings must be open to all affected
stakeholders including applicable regulatory authorities or governing bodies responsible for retail
electric service issues.” Reworded to say: “Meetings must be open to all affected NERC Registered
Entities including applicable regulatory authorities or governing bodies responsible for retail electric
service issues.” The concern is that stakeholders could be too broadly construed including residential,
commercial, industrial customers, and even more so (i.e transitory customers). We recommend that
the sentence be reworded as shown above. Additionally, GTC request feedback from the SDT's intent.
Is a stakeholder meeting required every year a planning assessment is done showing that nonconsequential load loss is required?
No
GTC does not understand how item #2b of Section II pertains to the Transmission Planner or the
Planning Coordinator. These types of assessments are beyond the scope of the Transmission Planner
or the Planning Coordinator and if necessary, should possibly be done by the Load Serving Entity. GTC
Recommends the SDT remove item #2b, the following sentence: “An assessment of the use of Firm
Demand interruption under footnote 12 on the health, safety, and welfare of the community.”
No
GTC would appreciate if the SDT could please clarify if the approval of a regulatory authority or
governing body is referring to the Regional Entity. The first sentence in Section III: “Approval of the
use of Firm Demand interruption under footnote 12 by the applicable regulatory authority or
governing body responsible for retail electric service issues is required if either:…”
The current draft for Requirement 5 (R5) of the NERC Standard TPL-001-3 Draft 1 reads as follows:
“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.” GTC has the
following comments regarding TPL-001-3, R5: If the responsible entity has criteria for transient
voltage response, along with criteria for acceptable system steady state voltage (including a precontingency high and low voltage limit, and a post-contingency high and low voltage limit), then
having a steady state post-contingency voltage deviation criteria does not affect the reliability of the
bulk electric system (BES). If the system response to a disturbance were to violate either the
transient response criteria, or the steady state maximum/minimum voltage criteria, there is potential
for loss of integrity of the BES. There is little to no potential for a loss of system integrity due soley to
a violation of the steady state voltage deviation criteria. Therefore, Georgia Transmission Corporation
requests that R5 not include a requirement to have criteria for post-Contingency voltage deviations.
Individual
Kathleen Goodman
ISO New England Inc.
No
For single contingency events, footnote 12 should be eliminated. Planning the electric system for nonconsequential load loss as a means to address a single contingency should not be acceptable. If the
footnote is to remain, as a minimum the attachment should be changed to increase the emphasis on
the near term nature of the use of non-consequential load shedding.
No
With regard to Section I, in paragraph I.5, the stakeholder process includes a dispute resolution
process. Existing ISO/RTO stakeholder processes are FERC approved and rigorous, requiring a dispute
resolution process goes beyond the existing requirements in ISO/RTO tariffs. Item I.5 should be
eliminated.
No
Section II, Paragraph 2b requires “an assessment of the use of Firm Demand interruption under
footnote 12 on the health, safety, and welfare of the community”. A great deal of subjectivity and
information that is not readily available to the Transmission Planner or Planning Coordinator would be
required to accurately access the effect of load shedding on the community as required by 2b.
Additionally Paragraphs II.3 and 4 require estimates of the frequency and duration of Firm Demand
interruption would be difficult to provide. These requirements should be deleted. These requirements

also undermine the deterministic nature of the Planning Standard. Paragraph II.2.5 that requires
future plans to mitigate the need for Firm Demand Interruption should be modified to again
emphasize the near term nature of single contingency non-consequential load shedding as a Planning
option.
No
Section III describes the instances where Approval of Interruptions of Firm Demand are required
under footnote 12. It is not clear whether under Paragraph III.1.a and Paragraph III.1.b the
Transmission Planner is to base the determination on either contingency or both contingencies i.e. is
“and” logic to be applied or is “or” logic used? Paragraph III.2 requires such approval for interruption
equal to or greater than 25 MW, this is a very small amount of load to be required to bring to a
stakeholder approval process for second contingency events. This amount should be increased to at
least 100 MW. Additionally in Section III, it is not clear who the “regulatory authority or governing
body responsible for retail electric service issues” is. Having this requirement in a reliability standard
not only is unnecessary, but also introduces regulatory requirements in a reliability standard. NERC
reliability standards should focus only on BES reliability, not any regulatory requirements. The
Attachment goes on to state “The Regional Entity determinations of Adverse Reliability Impacts are to
be evaluated by the Regional Entity through a published methodology approved by the ERO”. This is
essentially a “fill in the blank” requirement and makes it necessary to comment and approve the
footnote attachment without the benefit of reviewing a proposed methodology.
Individual
Bangalore Vijayraghavan
PG&E Company
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of
this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision

by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV in P1 is of no value. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of
footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 3 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column.
Individual
RoLynda Shumpert
South Carolina Electric and Gas
No
SCE&G does not agree with the proposed modifications to footnote b. SCE&G believes the original
footnote b is appropriate and consistent with the Energy Policy Act of 2005. SCE&G cites several
statements in the Energy Policy Act of 2005 as justification for our position. 1. The Energy Policy Act
of 2005 states: “The term ‘reliability standard’ means a requirement, approved by the Commission
under this section, to provide for reliable operation of the bulk-power system. The term includes
requirements for the operation of existing bulk-power system facilities, including cybersecurity
protection, and the design of planned additions or modifications to such facilities to the extent
necessary to provide for reliable operation of the bulk-power system, but the term does not include
any requirement to enlarge such facilities or to construct new transmission capacity or generation
capacity." It also states, “This section does not authorize the ERO or the Commission to order the
construction of additional generation or transmission capacity or to set and enforce compliance with
standards for adequacy or safety of electric facilities or services.” SCE&G believes the proposed
modifications to footnote b will result in building or enlarging facilities to meet the proposed
requirements. Also, any requirement that disallows load interruption or limits the amount of load
interruption infringes on the stated limitation on the ERO to not set and enforce compliance with
standards for adequacy. 2. It also states: The term ‘reliable operation’ means operating the elements
of the bulk-power system within equipment and electric system thermal, voltage, and stability limits

so that instability, uncontrolled separation, or cascading failures of such system will not occur as a
result of a sudden disturbance, including a cybersecurity incident, or unanticipated failure of system
elements.” In this statement there is no mention of disallowing the interruption of firm load. It only
requires that instability, uncontrolled separation, or cascading failures not occur. SCE&G believes the
proposed changes to footnote b are beyond the authority granted to the ERO by the Energy Policy
Act. 3. It also states: ‘‘Nothing in this section shall be construed to preempt any authority of any
State to take action to ensure the safety, adequacy, and reliability of electric service within that State,
as long as such action is not inconsistent with any reliability standard, …" SCE&G believes the
proposed modifications to footnote b infringe on the state’s authority to address adequacy and
reliability of electric service within the State.
No
See response to question #1
No
See response to question #1
No
See response to question #1
none
Group
ACES Power Member Standards Collaborators
Jason Marshall
ACES Power Marketing
No
We disagree with placing an upper limit on the amount of firm load shed. Conceptually, it seems like a
good idea but we do not believe that such a threshold could ever consider all of the potential issues
that could arise and would cause the need to plan to shed firm load. This is especially true considering
that the SAR clarifies that the upper threshold will be based on the existing planned load shedding
values. Future issues cannot be considered by such a data request. Consider a situation in which a
new transmission line was included in Planning Assessment but cannot be built because right of ways
cannot be obtained. Should an upper limit be placed on planned load shed in such a situation?
No
(1) Attachment 1 should clarify that it only applies when approval is not required by the regulatory
body with authority over retail service, such as local regulatory authorities and state public utility
commissions. This includes whether the approval is required by NERC rules or another regulatory
body’s rules. It does not make sense for the Transmission Planner or Planning Coordinator to
duplicate a process that is already required by another regulatory body that satisfies due process. As
an example, why should the Transmission Planner and Planning Coordinator have a dispute resolution
process if the regulatory body already has a dispute resolution process that can be used. It also does
not make sense for the Transmission Planner and Planning Coordinator to be compelled to have a
stakeholder comment process when the local regulatory body’s approval is required. Having such a
process is duplicative and unnecessary. (2) Many RTOs have well organized stakeholder processes
that could be utilized to satisfy Attachment I. Because the TPL standards apply to both the PC and TP,
one may believe the both the PC and TP need to have these stakeholder processes. Rather, we think
that the TP should be able to rely on its PC’s stakeholder process. We suggest Attachment I should
clarify that this is acceptable and that both entities are not required to have redundant processes. The
most important point is that stakeholders have an opportunity to participate.
No
(1) We disagree with with including the Facilities that will exceed their rating and the applicable
contingenices. We think this information should be treated as confidential. It could be used by bad
actors to create outages within communities. The risk to the Bulk Electric System is higher than the
benefit of sharing this information. (2) We disagree that the Transmission Planner should be required
to provide an assessment on the health, safety and welfare of the community. First, the stakeholders
will have an opportunity to provide this information through either the Transmission Planner’s
stakeholder comment process or through the local regulatory agency’s stakeholder comment process.
Second, these planned interruptions in firm demand are expected to be short in nature so the impacts

should be minimal. Third, an assessment on the health, safety and welfare of the community is an
unnecessary burden on the utility and is better suited for local governments. Even if the utility should
perform such an assessment, health, safety and welfare are ambiguous terms without clear
parameters or expectations for the data. Does this mean that the Transmission Planner verifies police
stations, fire departments, hospitals and other critical public support agencies are not included in the
planned load shed? Most electric providers already do this when developing load shed plans and are
likely not going to includes such customers in any load shed plan. Fourth, communities already have
plans in place for the interruption of electricity so as long a critical customers are not shed, then the
impacts are likely economic in nature. (3) Bullet 3 needs to be clarified that it is not an estimated
frequency but rather a historical frequency. How do you estimate a frequency for a new planned load
shed? It also needs to be clarified if the historical frequency is all instances within the Transmision
Planner’s area or just the specific location of the planned load shed. If it is all instances, it further
needs to be clarified that it is only within its own TP area. (4) We do not believe that expected
duration of the planned load shed should be required. Any duration will likely be a guess. When actual
contingencies occur, the time of restoration varies. Consider the recent event in Arizona and Southern
California. The report indicated that the TOP thought they could return the 500 kV line that initiated
the event in a few minutes. They were unaware that the phase angle was too large to close. The
expected duration is too speculative and should not be required. (5) We disagree with the need to
include future plans to mitigate the planned load shed in all cases. For remote areas of the system,
there simply may not be sufficient load growth to justify any other mitigation. (6) Item 8 should be
clarified that it applies only to the Planning Coordinator. The Planning Coordinator should coordinate
all of its Transmission Planner’s Planning Assessments. This would include evaluating planned load
shedding.
No
(1) What is the justification for selecting a 300 kV contingency as a threshold for requiring local
regulatory agency approval? What if the planned load shed is only for 1 MW? If a threshold is
required, we think it should be based on load size rather than contingency size? (2) What is the
justification for selecting 25 MW of planned firm load interruption as a threshold for requiring local
regulatory approval? The threshold could be set based off of the accompanying Section 1600 data
request. Since there are likely not many instances, it could be required for any new instance that
exceeds the existing planned load shed amounts. Thus, the threshold would be set just above existing
planned load interruptions. (3) A disclaimer should be added to clarify that an entity may still have to
seek local regulatory agency approval per the local regulatory agency’s rules. Nothing in the NERC
standard will change the local regulatory agency’s rules. (4) What if the local regulatory agency does
not want to address the planned load shed in the planning time frame? What is the Transmision
Planner required to do? While it is likely a local regulatory agency would be interested in addressing a
planned load interruption, nothing in the NERC or Commission rules can compel a local regulatory
agency to address such matters in a specific time frame. (5) Bullet 1.a is confusing. Is it intended to
say that if two Elements are part of a contingency and the Elements have different voltage classes,
the Element with the lowest voltage class must exceed the 300 kV threshold? If this is the case, the
bullet needs further clarification because it does not state this clearly. (6) The first paragraph after
section III appears to contradict bullets 1 and 2. Bullets 1 and 2 place contingency and load
thresholds on the planned firm load interruption. However, this paragraph says that the regulatoy
body responsible for retail electric service must approve the planned load shed before it can be used
in Year One of the planning assessment. If the purpose is for the thresholds to apply beyond Year One
and any instance in Year One to require approval, then the language regarding the thresholds needs
to clarify that the thresholds apply beyond Year One only. (7) We think it is redundant for the
Regional Entity to evaluate planned interruptions of firm load in its footprint. The Planning Coordinator
has a wide area view and is already required to do this for its footprint. The Planning Coordinator
already works with its neighbors to evaluate impacts. Requiring this evaluation by the Regional
Entities is arbitrarily based on historical and political boundaries. Many Planning Coordinators have
views that are broader than the Regional Entity view because they are in multiple regions. If this
evaluation will be required on a regional basis, why won’t it be required on an interconnection? (8)
The evaluation required by the Regional Entity may be completed before planned load interruption is
approved by local regulatory body. The TP and PC must submit the data based on their plan before
the local regulatory body approves the planned load interruption. The Regional Entity must complete
its evaluation within 45 days of receiving the information. There is no obligation for the local
regulatory body to act within 45 days. Wouldn’t it make more sense to evaluate the planned load

shed after it is approved by the local regulatory body?
(1) The standard needs to allow more flexibility regarding the use of planned load shed to address
transmission performance issues in the planning horizon. It needs to recognize that these planned
load shedding events may only be preliminary decisions for addressing problems that are several
years away. If there is little chance that the planned shed load will ever be relied upon in the
operating time horizon, there should be much less stringent requirements. For instance, if a PC or TP
relies on planned load shed for year five of the planning horizion but year one does not utilize the
planned load shed, they have four years to develop another solution. Why should great effort and
resources be expended in year five when another solution will likely be developed? (2) This standard
does not consider if the local regulatory body will act in time to approve the use of planned Firm
Demand interruption. We believe the standard needs to consider that the Planning Coordinator and
Transmission Planner may not be able to control the timelines of local regulatory agencies. As long as
the PC and TP have done their part by submitting the data, they should be able to rely on the planned
Firm Demand interruption until the local regulatory body acts. If the planned Firm Demand
interruption is not approved, then the TP and PC should be given more time to address the
transmission performance deficiency. (3) Several terms are used for the use of planned load shed.
Non-consequential load loss and Firm Demand interruption are two examples. We suggest using one
term consistently throughout the standard.
Individual
Steve Myers
Electric Reliability Council of Texas, Inc.
No
As an initial matter, ERCOT does not believe the planning process should allow for non-consequential
load shedding under single contingency conditions. However, if the SDT elects to retain a vehicle for
such exceptions, it should establish objective, reliability based criteria that lend themselves to
inclusion in a reliability standard. This is consistent with the general approach for reliability standards,
which prescribe the “what”, not the “how”. If the exceptions are based on objective criteria that are
known upfront, and those criteria reflect appropriate reliability based technical justifications, then the
risk of unwarranted exceptions to the general prohibition due to misuse of the exception process is
mitigated. Furthermore, the exception process should be external to the NERC Reliability Standards
(e.g. in the Rules of Procedure), which should merely reference authorized exceptions granted
pursuant to that process. In no case should a reliability standard mandate a stakeholder process in
any respect, procedural or substantive. In ISO/RTO regions, stakeholder processes fall within
ISO/RTO governance matters. These issues are beyond the purview of NERC Reliability Standards. In
other regions, although the relevant functional entities do not have stakeholder processes analogous
to ISOs/RTOs, any relevant processes are similarly beyond the scope of the reliability standards.
Accordingly, the SDT should eliminate all revisions related to the establishment of a stakeholder
process. As discussed in response to question 5, FERC is not requiring this approach, but rather has
only provided guidance with respect to ways to possibly bring the prior proposal in line with applicable
regulatory approval standards for reliability standards. Additionally, as a general matter, substantive
reliability standards requirements should not be imbedded within a footnote to a requirement. In this
case, not only is there a substantive requirement imbedded in the footnote, there is also a substantial
attachment (which must become part of the enforceable standard requirements)…and, to make it
worse, the attachment is an attachment to the footnote, rather than an attachment to and referred to
by a reliability standard requirement.
No
Please see ERCOT’s response to Question 1.
No
Please see ERCOT’s response to question 1 – the NERC Reliability Standards should not contain
requirements related to stakeholder processes, whether they are procedural or substantive. If an
exception process is retained, it should be outside of the NERC Reliability Standards (e.g. in the Rules
of Procedure). ERCOT also provides the following comments on Section II – the ERCOT comments are
in parentheses for easy reference and distinction relative to the proposed requirements. II.
Information for Inclusion in Item #3 of the Stakeholder Process The responsible entity shall document
the planned use of Firm Demand interruption under footnote ‘b’ which must include the following: (ERCOT COMMENT: This is all that is needed for this. The documentation would be relative to the

objective criteria developed for this purpose.) 1. Conditions under which Firm Demand interruption
under footnote ‘b’ 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 (ERCOT COMMENT: “1” is not necessary if objective criteria are
developed as benchmarks for the exception process. In that case, exceptions would only be allowed if
the objective criteria were met, regardless of the underlying assumptions related to conditions and
contingencies.) 2. Amount of Firm Demand MW to be interrupted with: a. The estimated number and
type of customers affected b. An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community (ERCOT COMMENT: The considerations
reflected in a and b are inappropriate for a reliability standard. Appropriate considerations for
reliability standards are related to the reliability performance of the system. The considerations in a
and b are more akin to quality of service issues better suited for regional policy discussions. It is not
within the purview of the SDT to address those matters.) 3. Estimated frequency of Firm Demand
interruption under footnote ‘b’ based on historical performance (ERCOT COMMENT: Historical
performance is irrelevant. If the SDT is going to retain revisions that accommodate non-consequential
load shedding, then the only relevant metrics are the objective criteria that set the benchmarks for
such exceptions.) 4. Expected duration of Firm Demand interruption under footnote ‘b’ based on
historical performance (ERCOT COMMENT: See ERCOT response to “3” above.) 5. Future plans to
mitigate the need for Firm Demand interruption under footnote ‘b’ (ERCOT COMMENT: This is
redundant to the requirement in the reliability standards that requires a plan to resolve any violations
identified in the planning process. Furthermore, if load shedding is allowed, this requirement doesn’t
make sense. Presumably the idea behind allowing these exceptions is to obviate the prospective need
for other alternatives. If that is not the case, then there is no need to allow the exceptions, because
the transmission upgrades to mitigate the need for load shedding can be established in the planning
horizon.) 6. Verification that TPL Reliability Standards performance requirements will be met following
the application of footnote ‘b’ (ERCOT COMMENT: The basis for the load shedding exception is to
provide a means to meet the TPL performance requirements in the context of a planning assessment.
Accordingly, this is redundant to the planning assessments, the point of whichis to identify and
resolve performance issues.) 7. Alternatives to Firm Demand interruption considered and the rationale
for not selecting those alternatives under footnote ‘b’ (ERCOT COMMENT: Load shedding exceptions
should be based on objective criteria and be reviewed pursuant to a process external to the NERC
reliability standards. Alternative discussions could be part of that external process.) 8. Assessment of
potential overlapping uses of footnote ‘b’ with adjacent planners (ERCOT COMMENT: It is not clear
what this means. Each functional entity performs assessments relative to its own system. This
appears to introduce a vague regional transmission planning requirement with no structure or rules
for such assessments.)
No
If non-consequential load shedding is allowed for single contingency conditions, as discussed above, it
should be based on objective critieria. As such, there is no need for the proposed stakeholder process,
including the Section III instances requiring regulatory approval. As with the other stakeholder
process sections, that section should be eliminated.
The SDT is not required to utilize the stakeholder approach by Order 762 or any other relevant FERC
orders. FERC merely provided guidance as to how the rejected proposal could be improved. However,
if the SDT elects to pursue an exception process, such exceptions should be based on objective
criteria, and the process should be external to the NERC Reliability Standards (e.g. in the Rules of
Procedure). In Order 693, FERC directed NERC to clarify footnote (b) to prohibit shedding firm load
except for consequential load loss (Order 693 at PP 1773, 1794 and 1797). In a related compliance
order, FERC reaffirmed its position. (130 FERC ¶ 61,200 (March 18, 2010) at PP 8-10 (Compliance
Order)) In a subsequent order, FERC clarified that its Order 693 directive did not preclude
consideration of specific comments related to planning the system based on load shedding at the
“fringes” of a system. (131 FERC ¶ 61,231 (June 11, 2010) at P 21 (Clarification Order)) FERC held
that regional variances for case-specific circumstances or a case-specific exception process to plan for
the loss of firm service “at the fringes of various systems” would be acceptable. (131 FERC ¶ 61,231
(June 11, 2010) at P 21 (Clarification Order)) However, FERC also stated that it viewed the basis for
such exceptions as economic, not reliability, with the justification being that it was not economic to
invest in the bulk electric system to serve all non-consequential load customers under some single
contingency conditions. (Order 693 at P 1792) FERC made clear that any such regional differences or

case specific exception processes cannot reflect the lowest common denominator, and, they must be
technically justified, and such justification must be strong. (Clarification Order at P 21. See also Order
693 at P 1794) This is consistent with FERC’s position that this is a matter of “fundamental issue of
transmission service”. (Order 693 at P 1793) In recognizing that meeting firm demand under single
contingency conditions is fundamental to transmission service, FERC noted that NERC’s definition of
firm transmission service is the "highest quality (priority) service offered to customers…that
anticipates no planned interruption.” (Order 693 at P 1793) Against this background, NERC filed
revisions to footnote b that allowed transmission plans to shed non-consequential load under single
contingency conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, (139 FERC ¶ 61,060 (April 19, 2012)) FERC rejected the
approach proposed by NERC and provided guidance on acceptable approaches to footnote b.
However, FERC did not endorse or mandate any particular approach. Rather, it merely urged “NERC
to develop in a timely manner an appropriate modification that is responsive to the Commission’s
directives in Order No. 693 and our concerns set forth in this Final Rule.” (Order 762 at P21) FERC
stated that in order for any such proposal to have merit, it must be technically justified and must not
reflect the lowest common denominator. As discussed, the proposed stakeholder approach is not
appropriate for NERC Reliability Standards. The SDT should abandon that approach and consider
simple revisions to footnote b that reference a case by case exception process based on objective
criteria that is external to the NERC Reliability Standards (e.g. Rules of Procedure). Alterantively, it
should develop revisions to the continent-wide standards that clarify that non-consequential load
shedding is not generally permitted for single contingency conditions, but, consistent with FERC’s
orders, exceptions could be established pursuant to regional rules based on the need/appropriateness
in a particular region. Consistent with the above discussion, if the SDT elects to pursue revisions that
accommodate shedding non-consequential load in transmission planning for single contingency
conditions, it should abandon the stakeholder process approach. The establishment of exceptions is
better suited for regional rules or pursuant to a process outside of the reliability standards – e.g. via
the Rules of Procedure, because such a process is not suited for a continent-wide reliability standard.
Regardless of whether the issue is addressed via an external process, or left to regional variances,
this issue needs to be addressed in a relatively timely manner because the uncertainty is affecting
planning processes.
Individual
Ed O'Brien
Modesto Irrigation Districtt
No
We do not agree with the concept of non-consequential load loss in light of historic application of N-1
criteria, that only provides for consequntial load loss.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues

to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this to load. Requiring the Regional Entity
to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL-001-3)
is duplicative and would increase the work load of the Regional Entities without improving reliability.
The TP and PC are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the application of footnote
‘b’ (see Section II.6) and the assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners” (see Section II.8), it is hard to imagine what type of review and verification is required to
show that “there are no Adverse Reliability Impacts including any potential cumulative effect within
the Regional Entity’s footprint”.
Group
Bonneville Power Administration
Chris Higgins
Transmission Reliability Program
No
BPA does not support quantitative limits on planned interruption, as planners generally do not plan
the system to interrupt demand for a single contingency. As stated in the proposed footnote b, “[a]n
objective of the planning process should be to minimize the likelihood and magnitude of interruption
of firm transfers or Firm Demand following Contingency events.” Setting a quantitative limit would
push transmission planners to plan the system to meet such a limit for a single contingency in all
cases. Moreover, a quantitative limit would be difficult to implement due to the wide variety of system
configurations and conditions. BPA believes an appropriate amount would be dependent on the
topography and the size of the system being planned.
No
Regarding the stakeholder process and dispute resolution, BPA believes that a decision for Firm
Demand interruption needs to be made based on what is best for the system, not a specific dispute
resolution process.
No
BPA does not support including information under Sections II.2.a and II.2.b, estimated number and
type of customers affected, or an assessment of the use of Firm Demand interruption on the health,
safety, and welfare of the community as this information does not support reliability of the BES. If
footnote b were applied, reliability of the BES is actually assessed by meeting the applicable TPL
Standard for a single contingency with loss of load regardless of the type of customers or use of Firm
Demand.
No
Regarding Section III.2 as stated above, BPA does not support quantitative limits on planned
interruption, as planners generally do not plan the system to interrupt demand for a single
contingency. Setting a quantitative limit would push transmission planners to plan the system to meet
such a limit for a single contingency in all cases.
Individual
R. Peter Mackin
Utility System Efficiencies, Inc.
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand
interruption under footnote b. This addition is overly prescriptive, unnecessary, and can have
unintended consequences on service reliability. We suggest deleting this sentence. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number
cannot account for variation even within one BA Area. This number will be too high for some planning
systems and too low for others. A fixed maximum number of MW for Non-Consequential Load Loss
under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not necessary. The first sentence of

this footnote states, “[a]n objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following Contingency events”. It is clear
that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand
interruption. Adding a fix maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum Non-Consequential Load Loss, the
Transmission Planner understands that the objective is to minimize the magnitude of the planned
interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount
of load under Footnote b. The Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed” amount.
No
We suggest removing item 5, “A dispute resolution process for any question or concern raised in #4
above that is not resolved to the stakeholder’s satisfaction”. Given that the “applicable regulatory
authorities or governing bodies responsible for retail electric service issues” are only one of the many
affected stakeholders, it is unclear how this dispute resolution process would treat stakeholders with
different concerns. For example, how would such a dispute resolution process take into account the
cost-benefit balance of load loss, which is the responsibility of the authorities responsible for retail
rates, if such an authority is only one of the many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of
customers affected) and II.2.b (An assessment of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community). We suggest removing them. Section II.2.a is
an administrative process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which makes compliance difficult. It can also become a
legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision
by the “applicable regulatory authorities or governing bodies responsible for retail electric service
issues”.
No
While we do not disagree with the intent, it is over-reaching for a NERC Standard to require action
from the applicable regulatory authority or governing body responsible for retail electric service issues
to approval of the use of Firm Demand interruption under footnote ‘b’. In any case, using 25 MW as
the threshold of loss of Non-Consequential Firm Demand for requiring approval is not realistic. As
stated in this questionnaire 25 MW came from registration limit for generation in the ERO Statement
of Compliance Registry Criteria. It will be a stretch to apply this value to load. Requiring the Regional
Entity to approve the Non-Consequential Load Loss under footnote b in TPL-002 (Footnote 12 in TPL001-3) is duplicative and would increase the work load of the Regional Entities without improving
reliability. The TP and PC are already required to make available to the affected stakeholders,
verification that TPL Reliability Standards performance requirements will be met following the
application of footnote ‘b’ (see Section II.6) and the assessment of potential overlapping uses of
footnote ‘b’ with adjacent planners” (see Section II.8), it is hard to imagine what type of review and
verification is required to show that “there are no Adverse Reliability Impacts including any potential
cumulative effect within the Regional Entity’s footprint”.
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is applied for
single contingency events in Category P1, but not for fault events in Category P2. Under Category P2
Single Contingency Event 3 Internal Breaker Fault no Non-Consequential Load Loss is allowed for
EHV, that is to say footnote 12 is conspicuously absent. Every Event in Category P1 Single
Contingency must be cleared with a breaker, and every breaker must meet the Internal Breaker Fault
requirement of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12, the appearance
of footnote 12 for EHV is inconsistent with P1. The footnote 12 should be added to Category P2 Single
Contingency Event 3 Internal Breaker Fault for EHV in the Non-Consequential Load Loss column. Also,
a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section Fault where no NonConsequential Load Loss is allowed for EHV. Where bus sections connect an element (Generator, Line,
Transformer, Shunt Device) to one or two breakers the bus section fault will remove the element from
service. Every EHV Event that includes footnote 12 in Category P1 Single Contingency that are
connected by a bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore the omission of

footnote 12 in the breaker internal fault event is "inconsistent with" the P1 event and we suggest
adding footnote 12 to the P2 Event 2 The footnote 12 should be added to Category P2 Single
Contingency Event 2 Bus Section Fault for EHV in the Non-Consequential Load Loss column. The new
definition of Non-consequential Load Loss compared to the last version seems to have deleted the
reference to Loads that may be lost during transient conditions due to under-frequency load shedding
(UFLS), while the reference to Load Loss due to under-voltage load shedding (UVLS) is retained. As a
result Load Loss due to UFLS would be part of Non-consequential Load Loss, and will not be allowed
under single contingency. Because UFLS may also be triggered during transient simulations, please
change the definition for Non-consequential Load Loss to read: "Non-Consequential Load Loss: NonInterruptible Load loss that does not include: (1) Consequential Load Loss, (2) the response of
voltage sensitive Load or frequency sensitive Load, or (3) Load that is disconnected from the System
by end-user equipment." It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting steady state
reliability requirements. Therefore, in Table 1, please change header-note "i" to read: "The response
of voltage sensitive Load and Frequency sensitive Load that is disconnected from the System by enduser equipment associated with an event shall not be used to meet steady state performance
requirements."

Consideration of Comments
TPL Table 1 Order – Project 2010-11

The TPL Table 1 Order Drafting Team thanks all commenters who submitted comments on the revision
of TPL-002 footnote ‘b’ and TPL-001 footnote 12. These standards were posted for a 30-day public
comment period from July 31, 2012 through August 29, 2012. Stakeholders were asked to provide
feedback on the standards and associated documents through a special electronic comment form.
There were 51 sets of comments, including comments from approximately 117 different people from
approximately 81 companies representing 9 of the 10 Industry Segments as shown in the table on the
following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
Due to comments received, the SDT has made the following changes to the text:
•
•

•

•

Effective date – updated to latest approved language
Main footnote
o Grammatical change from ‘should be’ the intent to ‘is’ the intent.
o Clarified the near-term and long-term requirements.
o Defined the ceiling threshold as 75 MW.
Attachment 1
o Section I
 Clarified that an existing process can be utilized, as long as it meets the criterion
in Section I.
 Changed ‘all affected stakeholders’ to ‘affected stakeholders’.
 Changed ‘specific applications’ to ‘specific locations’.
 Added statement that says that the process does not have to be repeated in
subsequent years if conditions haven’t changed.
o Section II
 Item 2.b has been clarified to better show the SDT’s intent.
 Item 8 has been changed from ‘planners’ to ‘Transmission Planners and Planning
Coordinators and clarified to indicate that it includes both the local and adjacent
entities.
o Section III
 Clarified role of regulatory authority.
 Deleted role of Regional Entity.
 Defined the ceiling threshold as 75 MW.
Footnote 12 only – Corrected terminology to use ‘Non-Consequential Load loss’ instead of ‘Firm
Demand interruption’.

The SDT is requesting that this project be moved forward to the initial ballot and comment phase of the
process.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

2

Index to Questions, Comments, and Responses

1.

Do you agree with the description and components of the the Stakeholder Process in the body of
the footnote including the maximum capacity threshold (currently shown as ‘x’ MW but the SDT
will fill in the value after the data request is complete and will submit the value for industry
comment and approval in the next posting)? If you do not support these changes or you agree in
general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. For the maximum capacity item, please supply any technical
rationale for your comment along with limiting conditions and any current criteria in use at your
entity........................................................................................................................ 11

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of
Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 33

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II
of Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 53

4.

Do you agree with the Instances for which Approval of Interruptions is required in Section III of
Attachment I? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ................................................................................................................ 72

5.

If you have any other comments on this Standard that you haven’t already mentioned above,
please provide them here. ............................................................................................ 98

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Sunitha Kothapalli

Additional Member

Puget Sound Energy
WECC 1, 3, 5

2. Peter (Pete) M Jones

Transmission Contracts

WECC 1, 3, 5

3. Kebede Jimma

Transmission Planning

WECC 1, 3, 5

4. Gary Shumate

Transmission Planning

WECC 1, 3, 5

5. Harris Wayne

Transmission Planning

WECC 1, 3, 5

6. Carol Jaeger

Transmission Planning

WECC 1, 3, 5

7. Zachery (Zach) Sanford

Transmission Planning

WECC 1, 3, 5

8. Eleanor Ewry

Transmission Planning

WECC 1, 3, 5

Group

3

X

4

5

6

7

8

9

10

X

Additional Organization Region Segment Selection

1. Joseph (Joe) W Seabrook Transmission Contracts

2.

X

2

Guy Zito

Northeast Power Coordinating Council

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization

Alan Adamson

New York State Reliability Council, LLC

NPCC 10

2.

Carmen Agavriloai

Independent Electricity System Operator

NPCC 2

3.

Greg Campoli

New York Independent System Operator

NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Chris de Graffenried Consolidated Edison Co. of New York, Inc. NPCC 1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8.

Kathleen Goodman

ISO - New England

NPCC 2

9.

Michael Jones

National Grid

NPCC 1

Hydro One Networks Inc.

NPCC 1

11. Michael R. Lombardi Northeast Utilities

NPCC 1

12. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

13. Bruce Metruck

New York Power Authority

NPCC 6

14. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Brian Robinson

Utility Services

NPCC 8

20. Michael Schiavone

National Grid

NPCC 1

21. Wayne Sipperly

New York Power Authority

NPCC 5

22. Donald Weaver

New Brunswick System Operator

NPCC 2

23. Ben Wu

Orange and Rockland Utilities

NPCC 1

24. Peter Yost

Consolidated Edison Co. of New York, Inc. NPCC 3

3.

Group

Jonathan Hayes

Additional Member

Additional Organization

Southwest Power Pool Reliability Standards
Development Team

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

City Utilities of Springfield

SPP

1, 4

Westar Energy

SPP

1, 3, 5, 6

4. Tiffany Lake

4

5

6

7

X

X

X

X

X

Region Segment Selection

1. Jonathan Hayes
John Allen

3

Region Segment Selection

1.

10. David Kiguel

2

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5. Harold Wyble

Kansas City Power and Light Company SPP

1, 3, 5, 6

6. Katy Onnen

Kansas City Power and Light Company SPP

1, 3, 5, 6

7. Don Taylor

Westar

1, 3, 5, 6

4.

Group

SPP

Bob Steiger

Salt River Project

2

X

3

4

X

5

6

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Brian Keel

5.

SRP

Group

WECC 1

WILL SMITH

MRO NSRF

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

MRO

1, 3, 5, 6

2.

CHUCK LAWRENCE ATC

OPPD

MRO

1

3.

TOM BREENE

WPS

MRO

3, 4, 5, 6

4.

JODI JENSON

WAPA

MRO

1, 6

5.

KEN GOLDSMITH

ALT

MRO

4

6.

ALICE IRELAND

XCEL

MRO

1, 3, 5, 6

7.

DAVE RUDOLPH

BEPC

MRO

1, 3, 5, 6

8.

ERIC RUSKAMP

LES

MRO

1, 3, 5, 6

9.

JOE DEPOORTER

MGE

MRO

3, 4, 5, 6

10. SCOTT NICKELS

RPU

MRO

4

11. TERRY HARBOUR

MEC

MRO

5, 6, 1, 3

12. MARIE KNOX

MISO

MRO

2

13. LEE KITTELSON

OTP

MRO

1, 3, 4, 5

14. SCOTT BOS

MPW

MRO

1, 3, 5, 6

15. TONY EDDLEMAN

NPPD

MRO

1, 3, 5

16. MIKE BRYTOWSKI

GRE

MRO

1, 3, 5, 6

17. DAN INMAN

MPC

MRO

1, 3, 5, 6

6.

Group

Jim Kelley

Additional Member

Additional Organization

SERC EC Planning Standards Subcommittee

X

X

Region Segment Selection

1. John Sullivan

Ameren

SERC

1

2. Bob Jones

Southern Company Services SERC

1

3. Pat Huntley

SERC

SERC

NA

4. Darrin Church

TVA

SERC

1

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

7.

Group

Additional Organization
East Kentucky Power Cooperative

SERC

1, 3, 5

2. Noman Williams

Sunflower Electric Power Corporation

SPP

1

3. David Albers

Brazos Electric Power Cooperative, Inc. ERCOT 1, 5

Group

Chris Higgins

4

5

6

7

8

9

X

Region Segment Selection

1. Ashley Gonyer

8.

3

ACES Power Member Standards
Collaborators

Jason Marshall

Additional Member

2

Bonneville Power Administration

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Chuck

Matthews

WECC 1

2. Allen

Chan

WECC 1, 3, 5, 6

Individual
10. Individual

Tim Ponseti, VP
Antonio Grayson

TVA Transmission Reliability Engineering &
Controls
Southern Company

X

X

X

X

11.

Individual

Janet Smith

Arizona Public Service Company

X

X

X

X

12.

Individual

Brandy A. Dunn

Western Area Power Administration

X

13.

Individual

Aaron Staley

Orlando Utilities Commission

X

14.

Individual

Chifong Thomas

BrightSource Energy, Inc.

15.

Individual

Jose H Escamilla

CPS Energy

16.

Individual

Mark Westendorf

MISO

17.

Individual

Jennifer Wright

San Diego Gas & Electric

18.

Individual

Patrick Brown

Essential Power, LLC

19.

Individual

Keith Morisette

X

X

X

X

X

X

X

X

X

9.

X
X

X

X

X

X

X

X
X

X
X

X

X

Individual

John Burnett

Tacoma Power
Los Angrles Department of Water and
Power

21.

Individual

Nazra Gladu

Manitoba Hydro

22.

Individual

Michael Falvo

Independent Electricity System Operator

23.

Individual

Kirit Shah

Ameren

X

X

X

X

24.

Individual

Thad Ness

American Electric Power

X

X

X

X

20.

X

X

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

7

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

25.

Individual

John Delucca

LCEC (Lee County Electric Cooperative

X

26.

Individual

Andrew Z. Pusztai

X
X

X

X

X

X

X

X

X

X

X

X

Individual
28. Individual

James Tucker
Brian Keel

29.

Individual

Andrew Gallo

City of Austin dba Austin Energy

30.

Individual

Anthony Jablonski

ReliabilityFirst

31.

Individual

Kayleigh Wilkerson

Lincoln Electric System

X

X

32.

Individual

Milorad Papic

Idaho Power Co.

X

X

33.

Individual

Martyn Turner`

X

Individual

Jonathan Fidrych

Individual

John Martinsen

LCRA Transmission Services Corporation
Tri-State Generation & Transmission
Association, Inc.
Public Utility District No. 1 of Snohomish
County

36.

Individual

Robert W. Creighton

Nova Scotia Power

X

37.

Individual

Greg Rowland

Duke Energy

X

38.

Individual

Chris de Graffenried

Consolidate Edison Co. of NY, Inc.

39.

Individual

Charlie Pottey

Sierra Pacific Power Co d/b/a NV Energy

40.

Individual

Richard Vine

California Independent System Operator

41.

Individual

charlie pottey

nevada power company dba nvenergy

X

42.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

43.

Individual

Chris Scanlon

Exelon

Individual
45. Individual

Catherine Mathews
Robert Casey

NorthWestern Energy (NWMT)
Georgia Transmission Corporation

46.

Kathleen Goodman
Bangalore
Vijayraghavan

ISO New England Inc.

34.
35.

44.

47.

Individual
Individual

8

9

10

X

American Transmission Company
Deseret Generation & Transmission
Cooperative
Salt River Project

27.

7

X

X

X

X

X

X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

PG&E Company

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

8

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

48.

Individual

RoLynda Shumpert

South Carolina Electric and Gas

Individual
50. Individual

Steve Myers
Ed O'Brien

Electric Reliability Council of Texas, Inc.
Modesto Irrigation Districtt

51.

R. Peter Mackin

Utility System Efficiencies, Inc.

49.

Individual

2

X

3

4

X

5

X

6

7

8

X

X
X

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

X

X
X

9

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: Thank you for following the new method of commenting that helps to avoid needless duplication of effort for
the SDT. Your company name will be included in the participant list and the comments in full will be reviewed by the drafting team
members under the Salt River Project comment/response.
Organization

Yes or No

Support Comments Submitted by Another Entity

Puget Sound Energy

Agree

Salt River Project

Sierra Pacific Power Co d/b/a NV Energy

Agree

WECC

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

10

1. Do you agree with the description and components of the Stakeholder Process in the body of the footnote including the
maximum capacity threshold (currently shown as ‘x’ MW but the SDT will fill in the value after the data request is complete and
will submit the value for industry comment and approval in the next posting)? If you do not support these changes or you agree
in general but feel that alternative language would be more appropriate, please provide specific suggestions in your comments.
For the maximum capacity item, please supply any technical rationale for your comment along with limiting conditions and any
current criteria in use at your entity.

Summary Consideration: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the
concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a stakeholder process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Several commenters suggested that there should be no limitation on the amount of Load that could be shed under footnote ‘b’. The
SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed out the
need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving
more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote
‘b’ utilization at 75 MW.
Several commenters asked about the distinction between long-term and near-term with respect to the use of footnote ‘b’. The SDT has
clarified the language to show that footnote ‘b’ is available for long-term planning as well as near-term planning but that the
stakeholder process only needs to be used for near-term.
The following changes were made due to industry comments:
First sentence of footnote text: An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

11

Next to last sentences in footnote text: In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to
ensure that BES performance requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term
Transmission Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the use
of Firm Demand interruption meets the conditions shown in Attachment 1.
Organization
Salt River Project
BrightSource Energy, Inc.
Los Angrles Department of Water and
Power
Deseret Generation & Transmission
Cooperative
California Independent System
Operator
nevada power company dba nvenergy
PG&E Company
Utility System Efficiencies, Inc.

Yes or No

Question 1 Comment

No

We do not agree with the imposition of a maximum limit on the amount of
planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. We suggest deleting this sentence.Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly
prescriptive. A single number cannot account for variation even within one
BA Area. This number will be too high for some planning systems and too
low for others.A fixed maximum number of MW for Non-Consequential
Load Loss under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not
necessary. The first sentence of this footnote states, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events”. It is clear that the spirit of the TPL Standard is to minimize the
likelihood and magnitude of Firm Demand interruption. Adding a fix
maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum NonConsequential Load Loss, the Transmission Planner understands that the
objective is to minimize the magnitude of the planned interruption under
footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of
planned Firm Demand loss could have the effect of giving “safe harbor” to
allow planned loss of that amount of load under Footnote b. The
Transmission Planner may now have more difficulty in avoiding NonConsequential Firm Demand Loss that is less than the “not to exceed”
amount.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

12

Organization

Yes or No

Question 1 Comment

ACES Power Member Standards
Collaborators

No

We disagree with placing an upper limit on the amount of firm load shed.
Conceptually, it seems like a good idea but we do not believe that such a
threshold could ever consider all of the potential issues that could arise and
would cause the need to plan to shed firm load. This is especially true
considering that the SAR clarifies that the upper threshold will be based on
the existing planned load shedding values. Future issues cannot be
considered by such a data request. Consider a situation in which a new
transmission line was included in Planning Assessment but cannot be built
because right of ways cannot be obtained. Should an upper limit be placed
on planned load shed in such a situation?

Bonneville Power Administration

No

BPA does not support quantitative limits on planned interruption, as
planners generally do not plan the system to interrupt demand for a single
contingency. As stated in the proposed footnote b, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events.” Setting a quantitative limit would push transmission planners to
plan the system to meet such a limit for a single contingency in all cases.
Moreover, a quantitative limit would be difficult to implement due to the
wide variety of system configurations and conditions. BPA believes an
appropriate amount would be dependent on the topography and the size of
the system being planned.

Manitoba Hydro

No

The maximum limit ‘x’ MW should vary with system load level and voltage.
For example, an ‘x’ MW interruption would be a very small fraction of a
5000 MW system load level compared to a 1000 MW load level. Similarly,
interruption of ‘x’ MW could be equal to surge impedance loading of a 230
kV line, where as it would be a fraction of a EHV transmission line loading.

NorthWestern Energy (NWMT)

No

Comments: A fixed maximum number of MW for Non-Consequential Load

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

13

Organization

Yes or No

Question 1 Comment
Loss should not be used in an industry-wide standard. There is too much
diversity. We suggest that a fixed maximum number not be stipulated.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
SERC EC Planning Standards
Subcommittee

No

We do not agree with this approach since there is no technical basis for
allowing load shedding. It is all an administrative process which could result
in inconsistencies from area to area. If a single contingency results in a local
network becoming temporarily radial, then load shedding within the local
network should be allowed. A limitation of up to some maximum amount of
load shedding (to be determined) should be imposed. This would provide a
technical basis for load shedding, which would help ensure consistency.

Southern Company

No

Southern does not agree with this Stakeholder Process approach since
there is no technical basis for allowing load shedding. It is all an
administrative process which could result in inconsistencies from area to
area. A more technical based approach was the one taken by the SDT in an
earlier draft - temporarily radial concept. If a single contingency (Category
B) results in a local network becoming temporarily radial, then load
shedding within the local network should be allowed since it would not
have any impact to the reliability of the transmission grid. A limitation of up
to some maximum amount ('x' MW) of load shedding (to be determined)
should be imposed. This would provide a technical basis for load shedding,
which would help ensure consistency from area to area. Furthermore, this
would provide a method for defining the "fringes" of the power system.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

14

Organization

Yes or No

Question 1 Comment

Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT agrees with you that there should be an upper limit on the amount of Firm Demand that can be shed. Order 762 also
pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
TVA Transmission Reliability
Engineering & Controls

No

TVA believes that the Stakeholder process is burdensome and should not
be required for all levels of footnote b use. TVA beleives that the
Stakeholder process should only be used for larger amounts of planned load
drop. TVA would like to propose the following: For load loss of less than 50
MW - only TP approval is required; for load loss up to 100 MW - PC
approval is required; for load loss up to 300 MW - RRO approval is
required. Any load loss over 300 MW would require both RRO & NERC
approval. The Stakeholder process would be required for any load loss of
100 MW or more. TVA is basing these levels using OE-417 as a starting point
- which must be filed for an uncontrolled load loss of 300 MW as well as
load shedding of 100 MW or more implemented under emergency
operational policy. TVA believes that the 300 MW is the maximum amount
of load that can be dropped without obtaining special permission from both
NERC and the RRO.

Response: The SDT does not agree with this suggestion, as the Order 762 data request showed that there were no utilizations of

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

15

Organization

Yes or No

Question 1 Comment

footnote ‘b’ involving more than 75 MW. Therefore, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW. The
data request also showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW.
MISO

No

Transmission planning that relies on planned or controlled interruption of
non-consequential firm load following loss of a single transmission facility
should not be acceptable and removal of footnote 12 should be considered
or a modification to allow its use only in conjunction with a petition to FERC
to waive (on an exception basis) the requirement to maintain firm load
service for a specifically identified system configuration issue warranting
Footnote 12’s application. If it is determined that a footnote provision is
required in the standard, we agree with the description and components of
the Stakeholder Process in the body of the footnote, but reserve judgment
on the value of the “x” that sets the maximum amount of MW load loss.
Also, we have comments on the reference to Attachment I. Please see our
comments under Q5.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a stakeholder process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW. Based on this fact,
and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW.
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

16

Organization

Yes or No

Question 1 Comment

See response to Q5.
San Diego Gas & Electric

No

Public Utility District No. 1 of
Snohomish County

No

We don’t support the changes.

Response: Without any reasons being supplied, the SDT is unable to respond to this comment.
Essential Power, LLC

No

Although we agree with the majority of the content of the footnote, we’re
not sure that using a specific amount of load as the bright-line threshold is
appropriate. For example, if we make the limit 25 MW, this will have a
different impact on different entities, in different regions. For a small TP
that may only have a total of 200 MW of load, 25 MW is a significant
amount of their overall obligation. For an area with 40,000 MW of load, 25
MW is hardly significant. Additionally, the nature of the load must be taken
into consideration as well. Some types of load are more acceptable to lose
than others; again, this may vary from region to region.Although we don’t
have a specific recommendation or solution regarding these issues, I would
urge the SDT to take these into consideration in their next revision.
The sentence that starts with “When interruption of Firm Demand is
utilized...” is confusing as it seems this sentence should only refer to the
limited circumstances mentioned within footnote b

Response: The Order 762 data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT
has kept the process threshold at 25 MW. No change made.
The SDT believes that in context the sentence you reference is clear; no change made.
Tacoma Power

No

The layout of Table 1 with “No 12” does not actually indicate that load loss
is allowed for those specific contingencies. Also the wording of the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

17

Organization

Yes or No

Question 1 Comment
footnote appears to require all Non-Consequential Load Loss to go through
the attachment 1 process, not just P1.1 to P1.5, P2.1 and P3.1 to P3.5.
Instead P1.1 to P1.5 and P3.1 to P3.5 should say “Yes per Attachment I” and
Footnote 12 should be eliminated entirely.
Since P2.1 is a new requirement with Version TPL-001-03, the recent NERC
survey did not capture utilities currently using Non-Consequential Load Loss
to address opening a line without a fault. Furthermore, some utilities may
not identify problem lines until their first assessment using TPL-001-3. P2.1
should have a new footnote reading “For this contingency, load which is
served radial from a remaining single source line may be shed as if it were
Consequential load.” Technical Background: Parallel transmission lines
serving remote load commonly will not perform with a P2-1 contingency,
particularly when the strong source is opened. These issues are particularly
common with load in rural settings and the cost to meet urban reliability
expectations will be disproportionally expensive. Utilities will be
encouraged to configure their system radially, which will be less reliable to
meet this rare contingency. FERC has not specifically addressed load
shedding associated with open ended lines. In order 693 the Commission
was responding to the contingencies in TPL-001-1 that included footnote b.
In order 762 and the NOPR RM12-1-000, FERC continues to reference
applicability of footnote b to the TPL-001 defined single contingencies, but
was otherwise prepared to accept Firm Load Loss for the single
contingencies in TPL-001-2 P2.2 to P2.4. In the TPL-001-2, the category of
“P2-Single Contingency” expanded to include both a new contingency of an
open ended line, and various bus and breaker faults that previously were
considered as Multiple Contingency.Based on our experience the likelihood
of a line opening is significantly less than for line equipment faults. In
addition, during human error caused line open events, personnel are onsite to affect quick restoration.
This standard should not impose an upper limit because any planned large

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

18

Organization

Yes or No

Question 1 Comment
load shedding will be reviewed and approved by the applicable regulatory
authority. Pending the survey outcome, a limit of 3000 MW consistent with
the CIP-002-5 Critical Asset level may be useful if the SDT believes an upper
limit is needed.

Response: The SDT believes that the layout of Table 1 is clear in its intent that the circumstances covered by footnote 12 permit
Load loss by exception and that the footnote pertains only to those Contingency types where the footnote appears. No change
made.
Although P2.1 is a “new” event, the resulting system will be the same as that following many P1.2 events; therefore, the SDT does
not see a need to add a new footnote to P2.1. No change made.
The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed
out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’
involving more than 75 MW. Based on this fact and after reviewing other aspects of the data, the SDT has set the proposed ceiling
on footnote ‘b’ utilization at 75 MW.
Independent Electricity System
Operator

No

Specific to the language used in footnote b, we agree with the concept of
an approval process for determining the acceptable level of Firm Demand
interruption applicable in a jurisdiction, and do not agree with prescribing a
fixed MW threshold for a continent-wide acceptable Firm Demand
interruption.Therefore, we recommend removing the last sentence in
footnote b) which reads “In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed ‘x’ MW.” and also the same
sentence from Attachement 1 section III. We believe there should not be a
fixed limit on the amount of Firm Demand interruption, for reasons
explained below in answers to Questions 4 and 5. As part of a reliability
standard, the footnote should clarify the conditions under which load
curtailment will be allowed, including mention of processes necessary to
manage special circumstances.
We generally agree with the reference to Attachment 1, but have concerns

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

19

Organization

Yes or No

Question 1 Comment
about the components of the Stakeholder Process described in Attachment
1, for reasons described in answers to Questions 2, 3 and 4.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
See responses to Questions 2, 3, 4, and 5.
Ameren

No

We believe that the NERC Glossary contains an adequate definition for Firm
Demand, which does not include Interruptible Demand or Demand-Side
Management Load. We do not believe that Interruptible Demand or
Demand-Side Management Load needs to be mentioned in the footnote b)
as these types of Demand are not Firm Demand. Interruptible Demand can
be cut at any time and may contain Demand-Side Management
components, and may be direct controlled by the System Operator.

Response: The SDT believes that mention of Interruptible Demand and Demand-Side Management Load within footnote ‘b’ adds
further clarity. No change made.
American Transmission Company

No

ATC agrees with the ‘x’ MW statement in footnote ‘b’ , however, supports a
maximum threshold value of 300 MW because this is the load loss
threshold that the DOE deems to be significant enough to warrant a NERC
system event investigation.

Response: The SDT does not agree with this suggestion. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
Salt River Project

No

Additional comment from SRP for Q #5.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

20

Organization

Yes or No

Consolidate Edison Co. of NY, Inc.

Question 1 Comment

No

See reply to Question 5

No

LES suggests the following changes to Footnote B/12 to further clarify the
drafting team’s intent. Under Footnote B/12, recommend the first sentence
be modified to state “An objective of the planning process is to minimize
the likelihood and magnitude of interruption...”.

Response: Please see response to Q5.
Lincoln Electric System

Additionally, please clarify the reference to the Near-Term Transmission
Planning Horizon while remaining silent on the Long-Term Transmission
Planning Horizon. Does Appendix 1 apply to the Long-Term Transmission
Planning Horizon as well as the Near-Term Transmission Planning Horizon?
Response: The SDT agrees with your suggested substitution of the word “is” for the words “should be” in the first sentence of the
footnote.
An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events.
The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term planning, but
that the stakeholder process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
LCRA Transmission Services Corporation

No

Footnote 12 is applied in column labeled “Non-Consequential Load Loss
Allowed.” However, the last sentence of the proposed Footnote 12
switches from using the terms Consequential Load Loss and NonConsequential Load Loss to using the term “Firm Demand.” The term “Firm
Demand” should be revised to “non-Consequential Load Load loss.”

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

21

Organization

Yes or No

Question 1 Comment
In addition, the application of Footnote 12 to the P3 contingency category
should be removed.

Response: The SDT agrees with your change and will use the term “Non-Consequential Load loss.”
The SDT does not agree that footnote 12 should be removed from the P3 Contingency category. The SDT clarifies that the Planning
Events for which footnote 12 is applicable were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011)
in its consideration of TPL-001-2. The proposed changes are outside the scope of this project, which aims to clarify the stakeholder
approval process. No change made.
Tri-State Generation & Transmission
Association, Inc.

No

There are several points that we disagree with in terms of the Stakeholder
Process in the body of the footnote. First, the footnotes are not written in a
manner so as to clearly be only applicable to Planning Standards. Many
parts of the footnotes and the Attachment I can be misconstrued as
Operational requirements. For example, the sentence that states
“Curtailment of firm transfer...” should state “Planned curtailment of firm
transfer...”
Second, we disagree with the imposition of a maximum limit on the amount
of planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. We suggest removal of this sentence.Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly
prescriptive. A single number cannot account for variation even within one
BA Area. This number will be too high for some planning systems and too
low for others.A fixed maximum number of MW for Non-Consequential
Load Loss under Footnote b in TPL-002 (and footnote 12 in TPL-001-3) is not
necessary. The first sentence of this footnote states, “[a]n objective of the
planning process should be to minimize the likelihood and magnitude of
interruption of firm transfers or Firm Demand following Contingency
events”. It is clear that the spirit of the TPL Standard is to minimize the
likelihood and magnitude of Firm Demand interruption. Adding a fixed

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

22

Organization

Yes or No

Question 1 Comment
maximum number of MW would seem unnecessary at best. At worst, it
could have unintended consequences. Without a fixed maximum NonConsequential Load Loss, the Transmission Planner understands that the
objective is to minimize the magnitude of the planned interruption under
footnote b (TPL-001-3, footnote 12).
Lastly, in an effort to develop a clearer and more transparent compliance
standard, it is recommended that the additional requirements imposed by
this footnote be broken into separate requirements set forth within the
body of the standard itself. Do not imbed requirements in footnotes.

Response: Because this footnote can only be applied to this specific standard, there should be no confusion as to the applicability to
planning. No change made.
The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also pointed
out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of footnote ‘b’
involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling
on footnote ‘b’ utilization at 75 MW.
The SDT disagrees with your characterization that requirements are being imbedded within the footnote. The requirement is clearly
stated within the body of the standard. The footnote is simply clarifying those special circumstances where some relief from a strict
interpretation of the requirement is permitted. No change made.
Hydro-Quebec TransEnergie

No

Comments: It is difficult to establish the maximum value for acceptable
Firm Demand interruption. For example, an entity may have an acceptable
maximum load loss to avoid impacts on the grid such as generation tripouts. For Hydro-Québec TransÉnergie (HQT), in the Québec
Interconnection, this value is above 1,000 MW. No maximum value should
be posted in Footnotes 12 and ‘b’, since it is specifically related to system
design and Interconnection size (inertia). Let us keep in mind that the goal
of the TPL standards is not service continuity of local loads but global
reliability of the system. Even though service continuity is important, TPL

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Organization

Yes or No

Question 1 Comment
standards should not address this issue by posting a maximum allowable
load loss.
Moreover, HQT considers that a Stakeholder Process such as seen in
Attachment I has no place in a standard and its footnotes. Mainly, the
Stakeholder Process doesn’t consider that entities may have their own
regulatory authorities with different processes, which do not specifically
establish this load loss value.

Response: The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762
also pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
Industry and the NERC BOT have approved the use of a Stakeholder Process to address the concerns with the original footnote ‘b’
and with footnote 12 in TPL-001-2. The SDT is now attempting to address FERC’s concern expressed in their Remand Order 762 that
NERC’s proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load
shed in a single Contingency provided that the plan is documented and alternatives are considered in an open and transparent
process, is vague, unenforceable, and not responsive to the previous Commission directives on this matter. The draft posted for
comment adds detail and specificity to the already-approved approach. The SDT does not believe it appropriate to move away from
the industry and BOT approved Stakeholder Process approach. No change made.
Exelon

No

For TPL-001, the wording for footnote 12 does not make clear that DSM
would be allowed without the Attachment 1 procedure. ComEd suggests
the following wording change:12. An objective of the planning process
should be to minimize the likelihood and magnitude of Non-Consequential
Load Loss following Contingency events. However, in limited circumstances
Non-Consequential Load Loss may be needed to ensure that BES
performance requirements are met. When Non-Consequential Load Loss is
utilized within the planning process to address BES performance
requirements (other than Interruptible or Demand Side Management load),
such interruption is limited to circumstances where the Non-Consequential

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

24

Organization

Yes or No

Question 1 Comment
Load Loss is meets the conditions shown in Attachment 1. In no case can
the planned Firm Demand interruption under footnote 12 exceed ‘x’ MW.
For TPL-002, the wording of footnote “b” is not totally clear that it applies
only to non-consequential load shed and not consequential load shed.
ComEd suggests that the wording of footnote “b” be changed as shown:b)
An objective of the planning process should be to minimize the likelihood
and magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm
Demand. It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the
Contingency, or (2) Interruptible Demand or Demand-Side Management
Load. Furthermore, in limited circumstances Firm Demand may need to be
interrupted to ensure that BES performance requirements are met. When
interruption of Firm Demand (other than in (1) or (2) above) is utilized
within the planning process to address BES performance requirements,
such interruption is limited to circumstances where the use of Firm Demand
interruption meets the conditions shown in Attachment 1. In no case can
the planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW.

Response: The SDT believes that footnote 12, as written and taken in context of the entire proposed TPL-001-2a standard, is clear.
Similarly, the SDT believes that footnote ‘b’ is clear, as well. No change made.
ISO New England Inc.

No

For single contingency events, footnote 12 should be eliminated. Planning
the electric system for non-consequential load loss as a means to address a
single contingency should not be acceptable.
If the footnote is to remain, as a minimum the attachment should be

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

25

Organization

Yes or No

Question 1 Comment
changed to increase the emphasis on the near term nature of the use of
non-consequential load shedding.

Response: The SDT disagrees with your suggestion to remove footnote 12 because there are some limited situations when
considering the entire North American grid where Non-Consequential Load loss may be necessary. No change made.
The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term planning, but
that the stakeholder process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
South Carolina Electric and Gas

No

SCE&G does not agree with the proposed modifications to footnote b.
SCE&G believes the original footnote b is appropriate and consistent with
the Energy Policy Act of 2005.SCE&G cites several statements in the Energy
Policy Act of 2005 as justification for our position.1. The Energy Policy Act
of 2005 states: “The term ‘reliability standard’ means a requirement,
approved by the Commission under this section, to provide for reliable
operation of the bulk-power system. The term includes requirements for
the operation of existing bulk-power system facilities, including
cybersecurity protection, and the design of planned additions or
modifications to such facilities to the extent necessary to provide for
reliable operation of the bulk-power system, but the term does not include
any requirement to enlarge such facilities or to construct new transmission
capacity or generation capacity."It also states, “This section does not
authorize the ERO or the Commission to order the construction of
additional generation or transmission capacity or to set and enforce
compliance with standards for adequacy or safety of electric facilities or
services.”SCE&G believes the proposed modifications to footnote b will
result in building or enlarging facilities to meet the proposed requirements.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

26

Organization

Yes or No

Question 1 Comment
Also, any requirement that disallows load interruption or limits the amount
of load interruption infringes on the stated limitation on the ERO to not set
and enforce compliance with standards for adequacy.2. It also states: The
term ‘reliable operation’ means operating the elements of the bulk-power
system within equipment and electric system thermal, voltage, and stability
limits so that instability, uncontrolled separation, or cascading failures of
such system will not occur as a result of a sudden disturbance, including a
cybersecurity incident, or unanticipated failure of system elements.”In this
statement there is no mention of disallowing the interruption of firm load.
It only requires that instability, uncontrolled separation, or cascading
failures not occur. SCE&G believes the proposed changes to footnote b are
beyond the authority granted to the ERO by the Energy Policy Act.3. It also
states: ‘‘Nothing in this section shall be construed to preempt any authority
of any State to take action to ensure the safety, adequacy, and reliability of
electric service within that State, as long as such action is not inconsistent
with any reliability standard, ..."SCE&G believes the proposed modifications
to footnote b infringe on the state’s authority to address adequacy and
reliability of electric service within the State.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

27

Organization
Electric Reliability Council of Texas, Inc.

Yes or No

Question 1 Comment

No

As an initial matter, ERCOT does not believe the planning process should
allow for non-consequential load shedding under single contingency
conditions. However, if the SDT elects to retain a vehicle for such
exceptions, it should establish objective, reliability based criteria that lend
themselves to inclusion in a reliability standard. This is consistent with the
general approach for reliability standards, which prescribe the “what”, not
the “how”. If the exceptions are based on objective criteria that are known
upfront, and those criteria reflect appropriate reliability based technical
justifications, then the risk of unwarranted exceptions to the general
prohibition due to misuse of the exception process is mitigated.
Furthermore, the exception process should be external to the NERC
Reliability Standards (e.g. in the Rules of Procedure), which should merely
reference authorized exceptions granted pursuant to that process. In no
case should a reliability standard mandate a stakeholder process in any
respect, procedural or substantive. In ISO/RTO regions, stakeholder
processes fall within ISO/RTO governance matters. These issues are beyond
the purview of NERC Reliability Standards. In other regions, although the
relevant functional entities do not have stakeholder processes analogous to
ISOs/RTOs, any relevant processes are similarly beyond the scope of the
reliability standards. Accordingly, the SDT should eliminate all revisions
related to the establishment of a stakeholder process. As discussed in
response to question 5, FERC is not requiring this approach, but rather has
only provided guidance with respect to ways to possibly bring the prior
proposal in line with applicable regulatory approval standards for reliability
standards.
Additionally, as a general matter, substantive reliability standards
requirements should not be imbedded within a footnote to a requirement.
In this case, not only is there a substantive requirement imbedded in the
footnote, there is also a substantial attachment (which must become part
of the enforceable standard requirements)...and, to make it worse, the

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

28

Organization

Yes or No

Question 1 Comment
attachment is an attachment to the footnote, rather than an attachment to
and referred to by a reliability standard requirement.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT disagrees with your characterization that requirements are being imbedded within the footnote. The requirement is clearly
stated within the body of the standard. The footnote is simply clarifying those special circumstances where some relief from a strict
interpretation of the requirement is permitted. No change made.
Modesto Irrigation Districtt

No

We do not agree with the concept of non-consequential load loss in light of
historic application of N-1 criteria, that only provides for consequntial load
loss.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

29

Organization

Yes or No

Question 1 Comment

would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Southwest Power Pool Reliability
Standards Development Team

Yes

As a concept we agree with the stakeholder process. We would like
clarification on why only the Near Term was used for non-consequential
load loss and not both Near and Long term. It seems that depending on the
time frame we would be held to different requirements of the standard.

Response: The SDT has clarified the language to show that footnote ‘b’ is available for long-term planning, as well as near-term
planning, but that the Stakeholder Process only needs to be used for near-term.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
MRO NSRF

Yes

The NSRF agrees with the ‘x’ MW statement in footnote b. The NSRF
suggests a maximum threshold value of 300 MW because this is the load
loss threshold that the DOE deems to be significant enough to warrant a
NERC system event investigation.To support the inclusion of planning to use
up to 300 MW of firm load shedding, registered Transmission Planning
entities or regional planning entities should provide a TPL type analysis that
demonstrates the use of planned firm load shedding allows BES equipment
to stay within emergency thermal, voltage, and frequency ranges, and
would not cause instability, uncontrolled separation, and cascading as
defined in the FPA Section 215.

Idaho Power Co.

Yes

Maximum threshold for Planned Firm Demand interruption should be
based on a previous year recorded peak demand. For instance for recorded
peak demand of more than 3,000 MW the maximum treshold should be

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

30

Organization

Yes or No

Question 1 Comment
greater than 300 MW.

Duke Energy

Yes

Situations where use of footnote ‘b’ would be appropriate can’t be readily
characterized with criteria leading to some “technically justified” maximum
capacity threshold for interruption. That being the case, a maximum
capacity threshold could be established based upon other criteria, such as
the 300 megawatt threshold for DOE disturbance reporting.

Response: The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW. Based on
this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75 MW.
Georgia Transmission Corporation

Yes

Please remove the “is” as shown below:”12. An objective of the planning
process should be to minimize the likelihood and magnitude of NonConsequential Load Loss following Contingency events. However, in limited
circumstances Non-Consequential Load Loss may be needed to ensure that
BES performance requirements are met. When Non-Consequential Load
Loss is utilized within the planning process to address BES performance
requirements, such interruption is limited to circumstances where the NonConsequential Load Loss [IS] meets the conditions shown in Attachment 1.
In no case can the planned FirmDemand interruption under footnote 12
exceed ‘x’ MW.”

Response: The SDT agrees with your suggested substitution of the word “is” for the words “should be” in the first sentence of the
footnote.
An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events.
LCEC (Lee County Electric Cooperative
American Electric Power

“No comment as we have no Firm Demand / Load customers.”
Yes

AEP believes it can support the language at this stage, but would like to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

31

Organization

Yes or No

Question 1 Comment
revisit this after the MW threshold has been determined.

Arizona Public Service Company

Yes

Orlando Utilities Commission

Yes

CPS Energy

Yes

City of Austin dba Austin Energy

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

32

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of Attachment I? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Comments raised several concerns on the following issues:
Stakeholder process is not needed: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address
the concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s
proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a stakeholder process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Proposed process duplicates or conflicts with existing regulator/RTO processes: The SDT agreed with the comments and revised
Footnote 12 accordingly. The text now allows for an existing process to be utilized, as long as it meets the criterion set out in
Attachment 1, Section I.
Scope of Stakeholder Participants: Some comments reflected concern that the term “all affected stakeholders” in Attachment 1, Part I
was too broad. The SDT has accepted the commenters’ view and has deleted ‘all’.
Clarification on need for annual Stakeholder Review: Commenters requested clarification as to whether the stakeholder processes has
to be repeated for each annual assessment for a project if the process has confirmed for that specific project it is acceptable to curtail a
firm demand. The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual
assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

33

Part I 2 b. Public Notification: The SDT agrees with the comment that: “Specific applications of the planned Firm Demand interruption
under footnote 12” could be considered to require detailed descriptions of each and every contingency that could lead to use of
footnote ‘b’ and is not necessary for the public notification. The language has been changed to clarify the SDT’s intent.
Implementation Plan: Several commenters mentioned that this process could turn out to be lengthy and that the Implementation Plan
should take this into account. The Implementation Plan for this project hasn’t changed from the one that was submitted with the
original filing, and is currently set at 60 months for footnote ‘b’.
Dispute resolution process is not required: The SDT concluded that a dispute resolution process is an essential part of the process. The
attachment language does not present any constraints on such a process; it just requires that an entity has a method to resolve
disputes.
The following changes were made due to industry comments:
Main Body of footnote text: In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that
BES performance requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission
Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Attachment 1 – Section I, last sentence: The responsible entity can utilize an existing process or develop a new process. The process
must include the following:
Attachment 1 – Section I, Bullet 1: Meetings must be open to affected stakeholders including applicable regulatory authorities or
governing bodies responsible for retail electric service issues
Attachment 1 – Section 1, Bullet 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:
Attachment 1 – Section I, Bullet 2b: Specific location(s) of the planned Firm Demand interruption under footnote ‘b’
Attachment 1 – Section I, last paragraph: An entity does not have to repeat the stakeholder process for a specific application of
footnote ‘b’ utilization with respect to subsequent Planning Assessments unless conditions spelled out in Section II below have
materially changed for that specific application.
Organization

Yes or No

Salt River Project

No

Question 2 Comment
We suggest removing item 5, “A dispute resolution process for any question or
concern raised in #4 above that is not resolved to the stakeholder’s satisfaction”.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

34

Organization

Yes or No

BrightSource Energy, Inc.

Question 2 Comment
Given that the “applicable regulatory authorities or governing bodies responsible for
retail electric service issues” are only one of the many affected stakeholders, it is
unclear how this dispute resolution process would treat stakeholders with different
concerns. For example, how would such a dispute resolution process take into
account the cost-benefit balance of load loss, which is the responsibility of the
authorities responsible for retail rates, if such an authority is only one of the many
stakeholders subject to dispute resolution?

Los Angrles Department of
Water and Power
Deseret Generation &
Transmission Cooperative
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation District
Utility System Efficiencies, Inc.

Response: The SDT believes that a dispute resolution process is an essential part of the Stakeholder Process. The SDT believes that
the dispute resolution process should include a method for accounting for the cost/benefit if it is an issue for the region. The
attachment language does not present any constraints on such a process; it just requires that an entity has a method to resolve
disputes. No change made.
MRO NSRF

No

American Transmission
Company

Order 890 already requires Transmission Planners to solicit the input of affected
stakeholders on TPL standards. Order 890 does not provide prescriptive details
regarding the stakeholder process for the TPL standards, which includes footnote ‘b’.
In additions, there is no clear justification to indicate that the process with regard to
footnote ‘b’ warrants more prescription stakeholder process details than the rest of
the TPL standards. So, the NSRF suggests that Section II be removed.
If Section I is not removed, then NSRF suggests at least replacing “all affected
stakeholders” with “all known affected stakeholders” or “appropriate known affected
stakeholders” because an entity can develop a list of all known affected entities for
compliance purposes and document that the meeting was open to them and that
they were notified. An entity cannot demonstrate that a stakeholder meeting is open

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

35

Organization

Yes or No

Question 2 Comment
to unknown stakeholders or that it notified unknown stakeholders.The use of “all” in
mandatory zero defect standards is not appropriate in NERC standards, especially
when potential large diverse populations such as affected stakeholders must be
considered.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT has tried to provide some technical/quantitative criteria in Section II to assist affected stakeholders in understanding why
Firm Demand is planned to be interrupted. No change made.
The SDT has accepted your comment and has replaced “all affected stakeholders” with “affected stakeholders.”
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
retail electric service issues
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:
TVA Transmission Reliability
Engineering & Controls

No

Please see comment for question #1. TVA believes that TPs should be able to drop
some load without having to go thru a burdensome process. Only the larger load
drop levels should require a Stakeholder review.

SERC EC Planning Standards

No

We recommend using a technical basis for load shedding instead of a Stakeholder

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

36

Organization

Yes or No

Subcommittee
Southern Company

Question 2 Comment
Process.

No

Southern recommends using a technical basis for load shedding (see comment in
Question 1 above) instead of a Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Please also see response to Q1.
ACES Power Member
Standards Collaborators

No

(1) Attachment 1 should clarify that it only applies when approval is not required by
the regulatory body with authority over retail service, such as local regulatory
authorities and state public utility commissions. This includes whether the approval
is required by NERC rules or another regulatory body’s rules. It does not make sense
for the Transmission Planner or Planning Coordinator to duplicate a process that is
already required by another regulatory body that satisfies due process. As an
example, why should the Transmission Planner and Planning Coordinator have a
dispute resolution process if the regulatory body already has a dispute resolution
process that can be used. It also does not make sense for the Transmission Planner
and Planning Coordinator to be compelled to have a stakeholder comment process
when the local regulatory body’s approval is required. Having such a process is
duplicative and unnecessary.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

37

Organization

Yes or No

Question 2 Comment
(2) Many RTOs have well organized stakeholder processes that could be utilized to
satisfy Attachment I. Because the TPL standards apply to both the PC and TP, one
may believe the both the PC and TP need to have these stakeholder processes.
Rather, we think that the TP should be able to rely on its PC’s stakeholder process.
We suggest Attachment I should clarify that this is acceptable and that both entities
are not required to have redundant processes. The most important point is that
stakeholders have an opportunity to participate.

Response: The SDT has revised the Stakeholder Process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following:
The SDT believes that a dispute resolution process is an essential part of the stakeholder process. No change made.
Bonneville Power
Administration

No

Regarding the stakeholder process and dispute resolution, BPA believes that a
decision for Firm Demand interruption needs to be made based on what is best for
the system, not a specific dispute resolution process.

Western Area Power
Administration

No

The addition of the "Stakeholder Process" outlines in Attachment 1 is so onerous so
as to persuade entities NOT to attempt the use of Footnote b) OR 12). Is this the
intent?

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

38

Organization

Yes or No

Question 2 Comment

not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
MISO

No

(1) The process presented in Section I of Attachment I is overly prescriptive. This
Section needs only to stipulate that the proposed utilization of the footnote be
reviewed through an open and transparent stakeholder process developed or
approved by the Regional Entities (since the RE will eventually need to review and
assess the reliability impact of such utilization), with supporting information.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered and adopted, subject to
stakeholder’s and regulatory authority’s approvals. Note that it is impractical to add
or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame
and hence the proposed provision does not allow for utilizing the footnote for the
interim period before new or reinforced transmission facilities are put in place. We
suggest to remove the word “Near-Term”.
(3) Requirement 8 of the Transmission Planning Standard TPL-001-3 requires
notification and response requirements for a Planning Coordinator and/or
Transmission Planner for the Planning Assessment to any registered entity having a
reliability interest. Attachment I does not recognize this requirement. Attachment I
must be coordinated with this administrative requirement.

Response: (1) Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns
with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

39

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Yes or No

Question 2 Comment

remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
(2) The Stakeholder process is required prior to planned interruption of Firm Demand in the near term, but does not preclude
application in the long term. The SDT clarified the language concerning near- and long-term applications of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
(3) Requirement R8 imposes an obligation on the Planning Coordinator and Transmission Planner to distribute its Planning
Assessment to: “any functional entity that has a reliability related need and submits a written request for information …”
Requirement R8 does not ensure the functional entity is aware that it may be affected by a plan to curtail firm Load so as to request
information. If a Planning Coordinator or Transmission Planner has established a stakeholder process, as per Attachment 1,
reporting of such a process under Requirement R8 is not prohibited. No change.
Public Utility District No. 1 of
Snohomish County

No

San Diego Gas & Electric

No

We don’t support the addition of stakeholder process language.

Response: With no reasoning provided, the SDT is unable to respond to this comment.
Tacoma Power

No

Completing the entire stakeholder process on an annual basis, before the TPL study
can be finalized, is not feasible due to long and unpredictable timelines for public
involvement and regulatory approval. The stakeholder process should only be
repeated when the technical basis as outlined in section II have changed, or when

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

40

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Yes or No

Question 2 Comment
there are new stakeholders.
There are cases on the fringes of the system where Firm Demand Interruption as the
preferred alternative in both the long term and short term, not as a temporary patch
in Corrective Action Plan.To address these issues, Section I should read as:Before the
use of Firm Demand interruption is allowed as an element in the Transmission
Planning Horizon of the Planning Assessment, the Transmission Planner or Planning
Coordinator shall ensure that the utilization of this mitigation is reviewed through an
open and transparent stakeholder process. The responsible entity shall document
the stakeholder process which shall include the following:1. Meetings must be open
to all 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 all 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
applications of the planned Firm Demand interruption under footnote 12 c.
Provisions for a stakeholder comment period 3. Information regarding the intended
purpose and scope of the proposed Firm Demand interruption 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. During each Planning Assessment, the Transmission
Planner or Planning Coordinator shall update the information outlined in Section II. If
the annual hours of exposure to or the amount of Firm Demand has increase above
the previously disclosed level(s), a new Stakeholder process shall be completed
within one Calendar year.Every three years the stakeholder process shall reoccur to
allow new stakeholders input to the process.

Response: The SDT has not adopted your proposed language: “Before the use of Firm Demand interruption is allowed as an element
in the Transmission Planning Horizon of the Planning Assessment,” as the SDT believes the reference to the Corrective Action Plan is

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

41

Organization

Yes or No

Question 2 Comment

superior. However, the SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each
annual assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has already provided a 60-month
implementation plan. No change made.
The information in Section II is required as part of the Stakeholder meeting. No change made.
Manitoba Hydro

No

A stakeholder process should not be required in jurisdictions where a legislation
already authorizes interruptions, as consent of stakeholders cannot override
legislation. If Firm Demand interruptions require the approval of regulatory authority
as described in Section III (for interruptions over 25 MW or if voltage level of the
contingency is greater than 300 kV), the stakeholder process described in Section I
would become a redundant process.
Does Section I exclude Firm Demand interruptions addressed under Section III?

Response: The SDT has revised the stakeholder process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
For interruptions over 25 MW, or if voltage level of the Contingency is greater than 300 kV, then both the Stakeholder Process and
the Section III regulatory review are still required.
Independent Electricity
System Operator

No

(1) The process presented in Section I and the rest of Attachment I is overly
prescriptive and lengthy. As part of a reliability standard, the footnote and process
must focus on the impact that Firm Demand interruption (or Load Rejection) would

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

42

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Yes or No

Question 2 Comment
have on the reliability of the Bulk Electric System and this aspect is covered in Section
III. This Section needs only to stipulate that the proposed utilization of the footnote
be reviewed through (a) an open and transparent stakeholder process and (b)
approved by a relevant reliability authority such as the ERO, Regional Entity or
applicable governmental authority since this authority will eventually need to review,
assess and approve the reliability impact on the interconnected BES of such
utilization, with supporting information. Reliability issues and their assessment and
approvals should be dealt with by the applicable reliability authority. Details of other
aspects of Firm Demand interruption, mainly the Stakeholder review and approval
process and issues pertaining to the quality of service, economic and welfare impacts
of Firm Demand interruption, assessment of alternatives (including their economic
and welfare impacts), etc. should be dealt with by the regulatory authority or
government body of each jurisdiction (in particular, in non-US jurisdictions), as is the
normal practice for all other Transmission Planning activities.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered and adopted, subject to
stakeholders’ and regulatory authorities’ approvals. Note that it is impractical to add
or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame
and hence the proposed provision does not allow for utilizing the footnote for the
interim period before new or reinforced transmission facilities are put in place. We
suggest removing the word “Near-Term”.

Response: (1) The SDT believes that the stakeholder process must involve all stakeholders affected and provide specific information
of the intended purpose and scope so they can understand the reason for Firm Demand interruption is appropriate. Industry and the
NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original footnote ‘b’ and
with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning Reliability

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

43

Organization

Yes or No

Question 2 Comment

Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that the plan is
documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable, and not
responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal as unjust,
unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not because it
contained a Stakeholder Process, but because they wanted the process better defined including a blend of quantitative and
qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft added
detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to move away
from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has provided a 60-month
implementation plan.
(2) The Stakeholder process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Ameren

No

We request that Item 1 be modified to include representatives of stakeholders
because it may not be practical to open a meeting to all affected stakeholders. The
new sentence of Attachment 1 should read, “Meetings must be open to all affected
stakeholders, or their representatives, including applicable regulatory authorities or
governing bodies responsible for retail electric service issues.”
Also, requirements for a meeting location would sem to eliminate electronic
partipation via webex. It would seem more practical for a TP or PC to host a specific
webex to present and discuss the issues associated with the need to drop Firm
Demand.
Further, we request that a MW threshold be included before the Section I
stakeholder process would begin, and believe that a minimum threshold of 10 MW of
Firm Demand to be cut would be a reasonable value to initiate a stakeholder process.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

44

Organization

Yes or No

Question 2 Comment
Levels below 10 MW would be considered as “noise” in the planning horizon. We
believe that an approval should be obtained in the Section I process, which would
eliminate the need for Section III. By requiring an approval of the appropriate local
governing bodies responsible for retail service issues (including rates), there is no
need to agree on a cap to limit the amount of Firm Demand dropped.

Response: The SDT agrees that the term “all affected stakeholders” in Attachment 1, Part I is too broad. The SDT has accepted the
commenters’ view and has replaced “all affected stakeholders” with “affected stakeholders.” The SDT has not included stakeholder
representatives, as this too would make identification of same impossible.
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
retail electric service issues
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:
The Stakeholder Process in Attachment 1 assumes that a meeting would be held; however, the language does not prohibit the use of
other methods acceptable to the stakeholders.
Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning
Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that
the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable,
and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal as
unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not
because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of quantitative
and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft
added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to
move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

45

Organization

Yes or No

Salt River Project

No

Question 2 Comment
Additional comment from SRP for Q #5.

Response: Please see response to Q5.
LCRA Transmission Services
Corporation

No

In the Proposed Revision to the Standard, Footnote 12 is applicable to the use of
Non-Consequential Load Loss to relieve criteria violations resulting from P1, P2, and
P3 category contingencies, however, Footnote 12 and Attachment I switch terms and
begins using “Firm Demand.” Though it may be reasonable to characterize NonConsequential Load Loss as a subset of Firm Demand not all Firm Demand is NonConsequential Load Loss. The term “Firm Demand” as used in Footnote 12 and
Attachment I should be replaced with “Non-Consequential Load Loss.” Application of
the term “Firm Demand” in Footnote 12 and Attachement 1 introduces an ecomonic
criteria to the TPL-001 Reliability Standard. For intstance, the interruption of “Firm
Demand” as defined in the NERC Glossary may not require Non-Consequential Load
Loss, however, this is an economic decision between the parties involved in the Firm
Demand contract. In addition, a Transmission Planner or Tranmission Owner may or
may not be a party to the Firm Demand contract.
The process outlined in Attachment 1 applies to the P3 contingency category
(through the application of Foontote 12) and thus represents a significant and
substantive change in the reliability standard over previous standards. The reference
to Footnote 12 should be deleted from the P3 contingency category.

Response: The SDT acknowledges that the references to Firm Demand interruption should reference Non-Consequential Load Loss.
The SDT has made revisions to the TPL-001-2a Footnote 12 and Attachment I to show these changes.
The SDT clarifies that the planning events for which footnote 12 is applicable were already vetted by industry and the NERC Board of
Trustees (approved on 8/4/2011) in its consideration of TPL-001-2. The proposed changes are outside the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
Tri-State Generation &

No

We disagree with Section I of Attachment I to the extent that there currently are
several other venues through which stakeholder input is mandated. In addition, we

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

46

Organization

Yes or No

Transmission Association, Inc.

Question 2 Comment
do not believe NERC Reliability Standards have the authority to dictate stakeholder
outreach processes. For several reasons, including the time required for public input,
permitting, acquisition, and construction, most transmission projects take several
years to build. TPs will develop plans to mitigate BES performance violations, but
those plans may not be able to be constructed in time. The Footnotes do not allow
planners to design temporary mitigation to accommodate real world construction
issues, which are often complex in nature due to competing interests.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT agrees that application of a stakeholder process could be lengthy and, consequently, has provided a 60-month
implementation plan.
Duke Energy

No

Since item 2 describes the public notice that must be provided, the phrasing of 2.b
should be revised to replace the words “Specific applications” with the words
“Summary description”. “Specific applications” could be considered to require
detailed descriptions of each and every contingency that could lead to use of
footnote ‘b’. That level of detail could certainly be provided to meeting participants,
but shouldn’t be necessary for the public notice.

Response: The SDT agrees with the comment that: “Specific applications of the planned Firm Demand interruption under footnote

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

47

Organization

Yes or No

Question 2 Comment

12” could be considered to require detailed descriptions of each and every contingency that could lead to use of footnote ‘b’ and is
not necessary for the public notification. The language has been changed to clarify the SDT’s intent.
Specific location(s) of the planned Firm Demand interruption under footnote ‘b’.
California Independent
System Operator

No

The process presented in Section I of Attachment I is overly prescriptive. Identifying
the need for stakeholder consultation on this issue within the consultation process
already employed by the Transmission Planner or Planning Coordinator should be
sufficient detail. In particular, however, we suggest removing item 5, “A dispute
resolution process for any question or concern raised in #4 above that is not resolved
to the stakeholder’s satisfaction”. Given that the “applicable regulatory authorities
or governing bodies responsible for retail electric service issues” are only one of the
many affected stakeholders, it is unclear how this dispute resolution process would
treat stakeholders with different concerns. For example, how would such a dispute
resolution process take into account the cost-benefit balance of load loss, which is
the responsibility of the authorities responsible for retail rates, if such an authority is
only one of the many stakeholders subject to dispute resolution?
There is no basis to support only allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment. The footnote itself
leaves the time frame wide open, and does not explicitly or implicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon,
when approval for transmission addition or reinforcement cannot be obtained for
whatever reasons, utilization of the footnote is considered. Note that it is impractical
to add or reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time
frame and hence the proposed provision does not allow for utilizing the footnote for
the interim period before new or reinforced transmission facilities are put in place.
We suggest removing the word “Near-Term”.

Response: The SDT has recognized that the requirement to notify all stakeholders is too broad and has replaced “all affected
stakeholders” with “affected stakeholders.”
Meetings must be open to affected stakeholders including applicable regulatory authorities or governing bodies responsible for
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

48

Organization

Yes or No

Question 2 Comment

retail electric service issues
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:
The SDT believes the stakeholder process is required and it must provide specific information of the intended purpose and scope so
stakeholders can understand the reason for Firm Demand interruption is appropriate. The SDT has debated the language and believe
that it is appropriate. No change made.
The Stakeholder Process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm
Demand interruption meets the conditions shown in Attachment 1.
Hydro-Quebec TransEnergie

No

The Stakeholder Process doesn’t consider that entities may have their own regulatory
authorities with different processes, which do not specifically establish load loss
values. Also, the use of Firm Demand interruption in the Corrective Plan should not
be limited only to the Near-Term Transmission Planning Horizon. It should also be
allowed for the Long-Term horizon, at least for Multiple Contingencies.

Response: The SDT has revised the Stakeholder Process to allow use of an existing regulator/RTO Stakeholder Process, as long as it
meets the criterion set in Attachment 1, Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
The Stakeholder process is required prior to planned interruption of Firm Demand, but does not preclude application in the long
term. The SDT has clarified the language concerning near- and long-term use of footnote ‘b’.
In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission Planning
Horizon to address BES performance requirements, such interruption is limited to circumstances where the use of Firm

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

49

Organization

Yes or No

Question 2 Comment

Demand interruption meets the conditions shown in Attachment 1.
NorthWestern Energy
(NWMT)

No

Comments: It is unclear how the dispute resolution process would treat stakeholders
with different concerns. We suggest that Item 5 of Attachment 1 be deleted.

Response: The SDT believes that a dispute resolution process is an essential part of the Stakeholder Process. No change made.
Georgia Transmission
Corporation

No

Item #1 in Section I should be reworded: From This....”Meetings must be open to all
affected stakeholders including applicable regulatory authorities or governing bodies
responsible for retail electric service issues.” Reworded to say: “Meetings must be
open to all affected NERC Registered Entities including applicable regulatory
authorities or governing bodies responsible for retail electric service issues.”The
concern is that stakeholders could be too broadly construed including residential,
commercial, industrial customers, and even more so (i.e transitory customers). We
recommend that the sentence be reworded as shown above.
Additionally, GTC request feedback from the SDT's intent. Is a stakeholder meeting
required every year a planning assessment is done showing that non-consequential
load loss is required?

Response: The SDT believes that the current language is clear and that the suggested change does not add further clarity. No change
made.
The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual assessment if the
process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the parameters have not
changed. If any changes have occurred to the original parameters, these issues must then be addressed in the Stakeholder Process
before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

50

Organization
ISO New England Inc.

Yes or No

Question 2 Comment

No

With regard to Section I, in paragraph I.5, the stakeholder process includes a dispute
resolution process. Existing ISO/RTO stakeholder processes are FERC approved and
rigorous, requiring a dispute resolution process goes beyond the existing
requirements in ISO/RTO tariffs. Item I.5 should be eliminated.

Response: The SDT has revised the stakeholder process to allow use of an existing regulator/RTO stakeholder process, as long as it
meets the criterion set in Section I.
The responsible entity can utilize an existing process or develop a new process. The process must include the following
The SDT concluded that a dispute resolution process is an essential part of the process and no change was made to the process.
South Carolina Electric and
Gas

No

See response to question #1

Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT’s response to Question 1.

Southwest Power Pool
Reliability Standards
Development Team

Yes

See comment From question 1

Response: Please see response to Q1.
Lincoln Electric System

Yes

Although LES agrees in general with the description and components included as part
of Section I, we suggest the following wording changes to enhance Section I.
Recommend the drafting team delete item 2(c) as it is duplicative of item 4 which is
more succinctly worded. Also, recommend additional wording be added to the end of
item 3 to provide meeting participants with advanced notice of the information. As
an example, “information...must be made available to meeting participants [ten days
prior to the meeting].”

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

51

Organization

Yes or No

Question 2 Comment

Response: The SDT believes that the current language is clear and that the suggested change does not add further clarity. No change
made.
LCEC (Lee County Electric
Cooperative

No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

Arizona Public Service
Company

Yes

Orlando Utilities Commission

Yes

CPS Energy

Yes

Essential Power, LLC

Yes

American Electric Power

Yes

City of Austin dba Austin
Energy

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

52

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of Attachment I? If you do
not support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the
concerns with the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is
vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach.
Based on industry comment, item 8 of Section II has been modified to clarify that adjacent Transmission Planners and Planning
Coordinators are the relevant parties for assessment of potential overlapping use of Firm Demand interruption.
Based on industry comment, item 2.b of Section II has been modified to clarify the SDT’s intent. However, the SDT believes assessment
of the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for understanding the
reliability impact and for stakeholders to make an informed decision. Such an assessment is already required under EOP-001-2.1b by
the Transmission Operator and Balancing Authority. A similar requirement for the Transmission Planner/Planning Coordinator would
rely on the same type of information and sources already required under the EOP standard.
Several commenters had concern about being required to provide the information in Section II, items 1, 2, 3 and 4. The SDT believes
that this information is necessary for understanding the reliability impact and for stakeholders to make an informed decision.
The following changes were made due to industry comments:
Attachment 1, Section II, Bullet 2b: Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health,
safety, and welfare of the community

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

53

Attachment 1, Section II, Bullet 8: Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent
Transmission Planners and Planning Coordinators
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.
Organization
Southwest Power Pool
Reliability Standards
Development Team

Yes or No

Question 3 Comment

No

We need clarification on the term planner in item 8 of section 2. Since the term isn’t
capitalized we would like to know if this was intended to mean Transmission Planner
or a adjacent Planning Coordinator for identifying a seams issue.
We would like see item 2b of section 2 removed this item isn’t relevant to the
standard and goes beyond the purpose of this standard. We understand that this is
included for curtailment of load during emergency conditions (EOP001 Attach 1) but
feel it is unnecessary in planning.

Response: The SDT agrees and item 8 of Section II has been modified accordingly.
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent Transmission Planners and Planning
Coordinators
The SDT believes assessment of the impact of Firm Demand interruption to the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community
Salt River Project
BrightSource Energy, Inc.

No

We disagree with the inclusion of the information in Section II.2.a (the estimated
number and type of customers affected) and II.2.b (An assessment of the use of Firm
Demand interruption under footnote ‘b’ on the health, safety, and welfare of the

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Organization

Yes or No

Question 3 Comment

Los Angrles Department of
Water and Power

community). We suggest removing them. Section II.2.a is an administrative process
and not needed for reliability of the Bulk Power System.

Deseret Generation &
Transmission Cooperative

Section II.2.b is vague and can be interpreted numerous ways, which make
compliance difficult. It can also become a legal liability issue for the service provider,
even if that loss of load is judged to be a prudent decision by the “applicable
regulatory authorities or governing bodies responsible for retail electric service
issues”.

Tri-State Generation &
Transmission Association, Inc.
California Independent
System Operator
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation Districtt
Utility System Efficiencies, Inc.

Response: The SDT believes that the provision of customers affected and the duration and assessment of the impact of Firm
Demand interruption on the health, safety, and welfare of the community is not solely administrative and is necessary for
understanding the reliability impact and for stakeholders to make an informed decision.
Based on comments received, the wording has been changed to clarify the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
MRO NSRF

No

American Transmission
Company

Order 890 already requires Transmission Planners to solicit the input of affected
stakeholders on TPL standards. Order 890 does not provide prescriptive details
regarding the information that should be included in the stakeholder process for the
TPL standards, which includes footnote ‘b’. Stakeholders that participate in
stakeholder meeting can ask for any information that they want regarding the

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Organization

Yes or No

Question 3 Comment
proposed use of Firm Demand interruption. They do not need a third party to
prescribe what information they need or want. So, the NSRF suggests that Section II
be removed.
If Section II is not removed, then the NSRF suggests that at least Items 2b, 6, and 8 be
removed from the listing. o Item 2b - The scope and content expectation for an
assessment of the potential impact of the proposed Firm Demand interruption on the
health, safety, and welfare of the community is basically broad, nebulous, and vague.
The stakeholders would raise any specific, relevant questions or concerns in these
areas if they exist without a prescriptive stipulation for this information in the TPL002 standard.
o Item 6 - The verification of that the TPL performance requirements will be met by
the use of Firm Demand interruption is superfluous. Proposal to use Firm Demand
interruption to meet the TPL-002 performance requirements would always be the
result of identifying (i.e. verifying) what Firm Demand interruption is needed to meet
the TPL-002 performance requirements.
o Item 8 - Potential overlapping uses of footnot ‘b’ with adjacent planners will not
always exist and would probably be rare. In addition, whenever the situation would
exist, then any applicable adjacent planners would be affected stakeholders and
would have the opportunity to attend the stakeholder meeting and raise any
questions or concerns in that meeting without the stipulation of this information in
the TPL-002 standard.

Response: Order 890 is not applicable to all NERC regions and is not a standard. No change made.
The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community

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Organization

Yes or No

Question 3 Comment

The SDT believes the wording regarding the TPL standards is necessary to ensure the focus on meeting the TPL standard’s reliability
requirements is not lost and that the end state following interruption of Firm Demand meets those requirements. No change made.
The SDT believes application of a wide area view to the use of Firm Demand interruption is necessary to avoid reliability issues that
would not be seen by an individual Transmission Planner or Planning Coordinator. There is no standard requirement for adjacent
Transmission Planner/Planning Coordinator’s to participate in Order 890 type processes therefore it must be addressed. No change
made.
SERC EC Planning Standards
Subcommittee

No

We recommend using a technical basis for load shedding instead of a Stakeholder
Process.

Southern Company

No

Southern recommends using a technical basis for load shedding instead of a
Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the
original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission
Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided
that the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague,
unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded
NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the
standard; not because it contained a Stakeholder Process, but because they wanted the process better defined including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate
to move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
ACES Power Member
Standards Collaborators

No

(1) We disagree with with including the Facilities that will exceed their rating and the
applicable contingenices. We think this information should be treated as
confidential. It could be used by bad actors to create outages within communities.
The risk to the Bulk Electric System is higher than the benefit of sharing this
information.
(2) We disagree that the Transmission Planner should be required to provide an
assessment on the health, safety and welfare of the community. First, the

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Yes or No

Question 3 Comment
stakeholders will have an opportunity to provide this information through either the
Transmission Planner’s stakeholder comment process or through the local regulatory
agency’s stakeholder comment process. Second, these planned interruptions in firm
demand are expected to be short in nature so the impacts should be minimal. Third,
an assessment on the health, safety and welfare of the community is an unnecessary
burden on the utility and is better suited for local governments. Even if the utility
should perform such an assessment, health, safety and welfare are ambiguous terms
without clear parameters or expectations for the data. Does this mean that the
Transmission Planner verifies police stations, fire departments, hospitals and other
critical public support agencies are not included in the planned load shed? Most
electric providers already do this when developing load shed plans and are likely not
going to includes such customers in any load shed plan. Fourth, communities already
have plans in place for the interruption of electricity so as long a critical customers
are not shed, then the impacts are likely economic in nature.
(3) Bullet 3 needs to be clarified that it is not an estimated frequency but rather a
historical frequency. How do you estimate a frequency for a new planned load shed?
It also needs to be clarified if the historical frequency is all instances within the
Transmision Planner’s area or just the specific location of the planned load shed. If it
is all instances, it further needs to be clarified that it is only within its own TP area.
(4) We do not believe that expected duration of the planned load shed should be
required. Any duration will likely be a guess. When actual contingencies occur, the
time of restoration varies. Consider the recent event in Arizona and Southern
California. The report indicated that the TOP thought they could return the 500 kV
line that initiated the event in a few minutes. They were unaware that the phase
angle was too large to close. The expected duration is too speculative and should not
be required.
(5) We disagree with the need to include future plans to mitigate the planned load
shed in all cases. For remote areas of the system, there simply may not be sufficient
load growth to justify any other mitigation.

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Yes or No

Question 3 Comment
(6) Item 8 should be clarified that it applies only to the Planning Coordinator. The
Planning Coordinator should coordinate all of its Transmission Planner’s Planning
Assessments. This would include evaluating planned load shedding.

Response: 1) The use of Firm Demand interruption and events involved should only affect local area issues and should not create
issues for the BES that could be exploited by “bad actors.” No change made.
2) The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent. As stated, it is something that TP/PC’s normally do.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3) Any estimate of future performance has to be based on some sort of available historical information, even for a new line/delivery.
The SDT believes it is clear that for stakeholders to make an educated decision regarding Firm Demand interruption, the information
must be provided for each instance of Firm Demand interruption use within the Transmission Planner/Planning Coordinator’s area.
No change made.
4) The SDT believes stakeholders need an expectation of the duration in order to evaluate the impact. No change made.
5) Possible future plans could include a decision not to mitigate the need for Firm Demand interruption. No change made.
6) The standard does not dictate who performs the assessment, only that one be performed. No change made.
Bonneville Power
Administration

No

BPA does not support including information under Sections II.2.a and II.2.b, estimated
number and type of customers affected, or an assessment of the use of Firm Demand
interruption on the health, safety, and welfare of the community as this information
does not support reliability of the BES. If footnote b were applied, reliability of the
BES is actually assessed by meeting the applicable TPL Standard for a single
contingency with loss of load regardless of the type of customers or use of Firm
Demand.

Response: The information is necessary to make an informed judgment and assessment, with stakeholder input, as to whether

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Yes or No

Question 3 Comment

reliability of the BES will be maintained. Evaluation of the consequences of an event is a part of assessing reliability. No change
made.
The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
TVA Transmission Reliability
Engineering & Controls

No

Under Item #2 - TVA is not sure how to properly address “health, safety, and welfare
of the community” from an regulatory standpoint. Please clarify what this would
require - such as number of hospitals without emergency backup, etc?
Also please see answer to question #1 - TVA beleives that only larger load drops
should require a Stakeholder review.

Response: The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the
community is necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on
comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
See response to Q1.
MISO

No

Again, this Section is overly prescriptive. This Section needs only to stipulate at a high
level, the kind of information needed to support the proposed utilization of the
footnote, leaving much of the detail to the application process overseen by the
Regional Entities (given the RE will eventually need to review and assess the reliability
impact of such utilization). We suggest the SDT to reduce this Section, or remove this
altogether with appropriate insertion into Section I that address a general need for
supporting information to be specified by the RE’s review process.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Organization
Independent Electricity
System Operator

Yes or No

Question 3 Comment

No

Again, this Section is overly prescriptive. This Section needs only to stipulate at a high
level, the kind of information needed to support the proposed utilization of the
footnote, leaving much of the detail to the application process overseen by the
applicable reliability authority to review and assess the reliability impact of such
utilization. We suggest the SDT to reduce this Section, or remove this altogether with
appropriate insertion into Section I that address a general need for supporting
information to be specified by the RA’s review process. Also note that use of a
“stakeholder process”, as per FERC’s concerns, must be crisp and clear.

Response: The SDT believes the information required provides what is necessary for a high-level assessment of the impact of
utilizing Firm Demand interruption and is necessary for stakeholders to make an informed decision. No change made.
Public Utility District No. 1 of
Snohomish County

No

San Diego Gas & Electric

No

We don’t support the addition of stakeholder process language.

Response: Without specific comments, the SDT is unable to respond.
Tacoma Power

No

Item II.2.b Since this is a stakeholder process, each stakeholder can make an
assessment for themselves about the effect of Firm Demand interruption on the
health, safety and welfare of the community. This requirement is too vague to be
enforceable.
Item II.5 Particularly in the case of P2.1 contingencies, utilities may not have any
plans to eliminate load shedding “at the fringes of various systems” as the FERC
NOPR noted would be acceptable.

Response: Stakeholders would not be likely to have all the information required to make an informed decision. The SDT is seeking
the appropriate balance between being too vague and too prescriptive. Based on comments received, the wording has been clarified
to better show the SDT’s intent.

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Organization

Yes or No

Question 3 Comment

2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
There is a requirement to include any mitigation plans, not a requirement to mitigate – doing nothing could be a possible plan. No
change made.
Manitoba Hydro

No

1 a. It would be very difficult to estimate the annual hours of exposure at or above a
certain load level.
2 b. An assessment on the health, safety, and welfare of the community should not
be part of a reliability assessment - this is purely subjective.
3 & 4. In situations where load interruption is a new proposal, historical data will not
be available. What does the SDT expect here?
5. Is there a requirement to mitigate? If there is a requirement to mitigate, the
required time frame is not identified.

Response: 1) Planning studies should provide the information necessary as to the Load levels at which the use of Firm Demand
interruption would be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the
duration. No change made.
2) The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is
necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received,
the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3 & 4) Any estimate of future performance has to be based on some sort of available historical information. Use of similarly situated
lines/deliveries allows for estimation of future performance.
5) There is a requirement to include any mitigation plans, not a requirement to mitigate – doing nothing could be a possible plan.
Ameren

No

We request that Items 5 and 7 also include information regarding estimated costs
and schedule for implementation. Any permitting issues associated with the

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Yes or No

Question 3 Comment
alternatives should also be included. Any previous attempts to build facilities but
were blocked should also be part of the record.

Response: Items 5 and 7 do not prohibit inclusion of cost, schedule information, or other project information and it is anticipated
these issues would normally be included. The SDT is seeking the appropriate balance between being too vague and too prescriptive.
No change made.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Salt River Project

No

Additional comment from SRP for Q #5.

Response: Please see response to Q5.
City of Austin dba Austin
Energy

No

Some of the information for inclusion in the Stakeholder Process is too burdensome
and of limited value. In particular, 2b and 4 can be deleted because the requested
information may not be available -- particularly if it is new load growth.

Response: The SDT believes assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the
community is necessary for understanding the reliability impact and for stakeholders to make an informed decision. Based on
comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Any estimate of future performance has to be based on some sort of available historical information. Use of similarly situated
lines/deliveries allows for estimation of future performance. No change made.
LCRA Transmission Services
Corporation

No

Requirement 1 only requires that the Transmission Planner provide system load data,
however, assumptions about system dispatch are also relevant. Requiring load
without dispatch will not provide a complete understanding of the conditions under
which Footnote 12 will apply. As a reliability standard, the Transmission Planner is
required to find a range of plausible system conditions under which a criteria

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Yes or No

Question 3 Comment
violation may be resolved.
The requirement (1a) to provide an estimate of the exposure creates an overly
burdensome requirement to investigate a wider range of possible operating
conditions than is currently performed.
Requirement 2a and 2b are overly burdensome on at Transmission
Planner/Transmission Owner who does not directly serve retail loads by placing a
requirement on the Transmission Planner/Transmission Owner to provide data that is
outside of its control to develop or maintain.

Response: The SDT believes the information in Section II is sufficient and would bring out any concerns related to dispatch
conditions. No change made.
Planning studies should provide the information necessary for 1.a as to the load levels at which the use of Firm Demand interruption
would be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the duration.
The SDT believes 2.a and 2.b’s provision of customers affected and duration and assessment of the impact of Firm Demand
interruption on the health, safety, and welfare of the community is necessary for understanding the reliability impact and for
stakeholders to make an informed decision. Based on comments received, the wording for 2.b has been clarified to better show the
SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Duke Energy

No

In Item #8, replace the word “planners” with the words “Transmission Planners”.

Response: The SDT agrees, and item 8 of Section II has been modified accordingly.
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent Transmission Planners and Planning
Coordinators
Hydro-Quebec TransEnergie

No

For example, under 2 b., assessment of the impacts of interruptions on health, safety,
or welfare of the community is not information that could be reasonably expected to
be available to system planners. All loads may face interruptions from time to time,

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Yes or No

Question 3 Comment
and the impact on health, safety or welfare is very difficult to identify. This item
should be deleted.

Georgia Transmission
Corporation

No

GTC does not understand how item #2b of Section II pertains to the Transmission
Planner or the Planning Coordinator. These types of assessments are beyond the
scope of the Transmission Planner or the Planning Coordinator and if necessary,
should possibly be done by the Load Serving Entity.GTC Recommends the SDT
remove item #2b, the following sentence:”An assessment of the use of Firm Demand
interruption under footnote 12 on the health, safety, and welfare of the community.”

Response: Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. A
similar requirement for the Transmission Planner/Planning Coordinator would rely on the same type of information and sources
already required under the EOP standard. The SDT believes assessment of the impact of Firm Demand interruption on the health,
safety, and welfare of the community is necessary for understanding the reliability impact and for stakeholders to make an informed
decision. Based on comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
NorthWestern Energy
(NWMT)

No

Comments: The estimated number and type of customers affected is not needed for
reliability of the Bulk Power System. We suggest removing Item 2a in Section II of
Attachment 1.
An assessment of the health, safety, and welfare of the community should not be
required. It is too vague and coud present legal problems. We suggest removing
Item 2b in Section II of Attachment 1.

Response: The SDT believes provision of customers affected and duration and assessment of the impact of Firm Demand
interruption on the health, safety, and welfare of the community is necessary for understanding the reliability impact and for
stakeholders to make an informed decision.
Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. The SDT believes
assessment of the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for
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Yes or No

Question 3 Comment

understanding the reliability impact and for stakeholders to make an informed decision. Based on comments received, the wording
has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
ISO New England Inc.

No

Section II, Paragraph 2b requires “an assessment of the use of Firm Demand
interruption under footnote 12 on the health, safety, and welfare of the community”.
A great deal of subjectivity and information that is not readily available to the
Transmission Planner or Planning Coordinator would be required to accurately
access the effect of load shedding on the community as required by 2b.
Additionally Paragraphs II.3 and 4 require estimates of the frequency and duration of
Firm Demand interruption would be difficult to provide. These requirements should
be deleted. These requirements also undermine the deterministic nature of the
Planning Standard.
Paragraph II.2.5 that requires future plans to mitigate the need for Firm Demand
Interruption should be modified to again emphasize the near term nature of single
contingency non-consequential load shedding as a Planning option.

Response: Such an assessment is already required under EOP-001-2.1b by the Transmission Operator and Balancing Authority. A
similar requirement for the Transmission Planner/Planning Coordinator would rely on the same type of information and sources
already required under the EOP standard. The SDT believes assessment of the impact of Firm Demand interruption on the health,
safety, and welfare of the community is necessary for understanding the reliability impact and for stakeholders to make an informed
decision. Based on comments received, the wording has been clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
Planning studies should provide the information necessary as to the Load levels at which the use of Firm Demand interruption would
be required. Evaluation of annual Load profiles where the Load level is exceeded would allow estimation of the duration. Any
estimate of future performance has to be based on some sort of available historical information. Use of similarly situated

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Question 3 Comment

lines/deliveries allows for estimation of future performance. No change made.
A purpose of the stakeholder process is to ensure those impacted by use of Firm Demand interruption and the regulators responsible
for quality of service have input on its use and the acceptability of the mitigation plan. No additional elaboration on the use of Firm
Demand interruption in the standard is necessary. No change made.
South Carolina Electric and
Gas

No

See response to question #1

Response: Please see response to Q1.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT’s response to question 1 - the NERC Reliability Standards should
not contain requirements related to stakeholder processes, whether they are
procedural or substantive. If an exception process is retained, it should be outside of
the NERC Reliability Standards (e.g. in the Rules of Procedure).
ERCOT also provides the following comments on Section II - the ERCOT comments are
in parentheses for easy reference and distinction relative to the proposed
requirements. II. Information for Inclusion in Item #3 of the Stakeholder ProcessThe
responsible entity shall document the planned use of Firm Demand interruption
under footnote ‘b’ which must include the following: - (ERCOT COMMENT: This is all
that is needed for this. The documentation would be relative to the objective criteria
developed for this purpose.)
1. Conditions under which Firm Demand interruption under footnote ‘b’ would be
necessary:a. System Load level and estimated annual hours of exposure at or above
that Load levelb. Applicable Contingencies and the Facilities outside their applicable
rating due to that Contingency(ERCOT COMMENT: “1” is not necessary if objective
criteria are developed as benchmarks for the exception process. In that case,
exceptions would only be allowed if the objective criteria were met, regardless of the
underlying assumptions related to conditions and contingencies.)
2. Amount of Firm Demand MW to be interrupted with:a. The estimated number and

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Question 3 Comment
type of customers affectedb. An assessment of the use of Firm Demand interruption
under footnote ‘b’ on the health, safety, and welfare of the community(ERCOT
COMMENT: The considerations reflected in a and b are inappropriate for a reliability
standard. Appropriate considerations for reliability standards are related to the
reliability performance of the system. The considerations in a and b are more akin to
quality of service issues better suited for regional policy discussions. It is not within
the purview of the SDT to address those matters.)
3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on
historical performance(ERCOT COMMENT: Historical performance is irrelevant. If the
SDT is going to retain revisions that accommodate non-consequential load shedding,
then the only relevant metrics are the objective criteria that set the benchmarks for
such exceptions.)
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on
historical performance(ERCOT COMMENT: See ERCOT response to “3” above.)
5. Future plans to mitigate the need for Firm Demand interruption under footnote
‘b’(ERCOT COMMENT: This is redundant to the requirement in the reliability
standards that requires a plan to resolve any violations identified in the planning
process. Furthermore, if load shedding is allowed, this requirement doesn’t make
sense. Presumably the idea behind allowing these exceptions is to obviate the
prospective need for other alternatives. If that is not the case, then there is no need
to allow the exceptions, because the transmission upgrades to mitigate the need for
load shedding can be established in the planning horizon.)
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’(ERCOT COMMENT: The basis for the load
shedding exception is to provide a means to meet the TPL performance requirements
in the context of a planning assessment. Accordingly, this is redundant to the
planning assessments, the point of whichis to identify and resolve performance
issues.)

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Question 3 Comment
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote ‘b’(ERCOT COMMENT: Load shedding
exceptions should be based on objective criteria and be reviewed pursuant to a
process external to the NERC reliability standards. Alternative discussions could be
part of that external process.)
8. Assessment of potential overlapping uses of footnote ‘b’ with adjacent
planners(ERCOT COMMENT: It is not clear what this means. Each functional entity
performs assessments relative to its own system. This appears to introduce a vague
regional transmission planning requirement with no structure or rules for such
assessments.)

Response: Please see response to Q1.
1. The SDT believes the information in Section II is necessary for stakeholders to understand the reason Firm Demand interruption
use is appropriate and make an informed decision. No change made.
2. The SDT believes the information in section II is necessary for stakeholders to understand the reason Firm Demand interruption
use is appropriate and make an informed decision. The SDT believes provision of customers affected and duration and assessment of
the impact of Firm Demand interruption on the health, safety, and welfare of the community is necessary for understanding the
reliability impact and for stakeholders to make an informed decision. Based on comments received, the wording for 2.b has been
clarified to better show the SDT’s intent.
2b. Assessment of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community
3. and 4. The SDT believes the information in Section II is necessary for stakeholders to understand the reason Firm Demand
interruption use is appropriate and make an informed decision. Any estimate of future performance has to be based on some sort of
available historical information even for a new line/delivery. The SDT believes it is clear that for stakeholders to make an educated
decision regarding Firm Demand interruption, the information must be provided for each instance of Firm Demand interruption use
within the Transmission Planner/Planning Coordinator’s area. No change made.
5. The mitigation plan identifies how reliability violations will be avoided in the future where projects or other actions are not
available in time or are not cost effective. No change made.

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Yes or No

Question 3 Comment

6. The SDT believes the wording regarding the TPL standards is necessary to ensure the focus on meeting the TPL standard’s
reliability requirements is not lost and that the end state following interruption of Firm Demand meets those requirements. No
change made.
7. Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed Transmission Planning
Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single Contingency provided that
the plan is documented and alternatives are considered in an open and transparent process (“footnote b”), is vague, unenforceable,
and not responsive to the previous Commission directives on this matter. Accordingly, the Commission remanded NERC’s proposal
as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC remanded the standard; not
because it contained a Stakeholder Process, but because they wanted the process better defined, including a blend of quantitative
and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained. This draft
added detail and specificity to the already-approved approach. Based on these facts, the SDT does not believe it appropriate to
move away from the industry and Board of Trustees approved Stakeholder Process approach. No change made.
8. The SDT believes application of a wide area view to the use of Firm Demand interruption is necessary to avoid reliability issues that
would not be seen by an individual Transmission Planner/Planning Coordinator. The SDT believes assessment for Adverse Reliability
Impacts is an appropriate step. However, the SDT has moved this responsibility to the ERO and deleted the Regional Entity from any
involvement.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Orlando Utilities Commission

Yes

Data element 5 should probably read. "List any Future Plans or future system changes
to mitigate the need for Firm Demand Interruption under footnote 'b'". There can be
cases where there is no planned future project to relive the problem, or it could be
expected that load will go down or changes on neighboring systems will relieve the
problem.

Response: Possible future plans could include a decision not to mitigate the need for Firm Demand interruption. No change made.

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Yes or No

LCEC (Lee County Electric
Cooperative

Question 3 Comment
No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

Arizona Public Service
Company

Yes

CPS Energy

Yes

Essential Power, LLC

Yes

American Electric Power

Yes

Lincoln Electric System

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

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4.

Do you agree with the Instances for which Approval of Interruptions is required in Section III of Attachment I? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: The 25 MW threshold for requiring regulatory authority review was questioned by several entities. The
original 25 MW threshold came from the Registry Criteria for Load-Serving Entities. The data request showed that the average value of
footnote ‘b’ utilization was approximately 19 MW. Therefore, the SDT has decided to leave the process threshold at 25 MW.
Several entities questioned having the 300 kV threshold for Contingencies because it has no material impact to Load and that the
threshold should be based on a MW amount only. The SDT believes that the 300 kV threshold is appropriate, as the proposed TPL-0012, which was accepted by industry and the NERC Board of Trustees, made a distinction between HV and EHV and the handling of
Contingencies based on the 300 kV level. The SDT believes that the establishment of this threshold within footnote ‘b’ is consistent with
that approach and places the proper emphasis on EHV.
Several entities had concerns that actions from a regulatory body won’t happen quickly enough and that such a requirement was not
appropriate for a reliability standard. There were also concerns voiced about inconsistencies in such an approach. The SDT understands
these concerns and has clarified the language to assist in alleviating such concerns. The SDT also advises any entity wishing to utilize
footnote ‘b’ in its planning process to start that process at an appropriate time so that it can be completed by the needed date.
Some concerns were raised about the role of the Regional Entity in this process. After reviewing the submitted comments, the SDT
agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now placed on
NERC as the ERO. This change should help to promote continent-wide consistency.
The following changes were made due to industry comments:
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the
applicable regulatory authority or governing body responsible for retail electric service issues does not object to the use of Firm Demand
interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.
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Southwest Power Pool
Reliability Standards
Development Team

Yes or No

Question 4 Comment

No

Need clarification around why the 25MWs threshold on generation was thrown into
load interruption topic. Looking at the registry criteria for generation the threshold
should be 20Mws for a single unit and 75 MWs for aggregated units. Not sure where
the 25MWs threshold came from for generation. The 25 MW threshold in Section III
is duplicative of the registration limit for generation in the ERO Statement of
Compliance Registry Criteria. It is submitted for comment at this time but will not be
finalized until after the above mentioned data request is complete and the final value
will be submitted for industry comment and approval in the next posting. The GOP
registration criteria is 20MWs. Whereas the registration criteria for LSEs and DPs is
25MWs. There appears to be some co mingling of criteria. Additionally this raises
the question of whether x =25MWs. Please clarify which you intended to use.
We are concerned that getting retail service regulatory authority approval in a quick
manner could be difficult. We are also concerned that if it does get caught in the
process of being approved and there is no time to construct, that we would not want
to be found out of compliance due to something that is out of our control.

Response: The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and
Operators. The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the
process threshold at 25 MW. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than
75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’
utilization at 75 MW.
The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some of
the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will be
completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
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Salt River Project

Yes or No

Question 4 Comment

No

While we do agree with the intent, it is over-reaching for a NERC Standard to require
action from the applicable regulatory authority or governing body responsible for
retail electric service issues to give approval of the use of Firm Demand interruption
under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.
MRO NSRF

No

The NSRF suggests that Section III be removed for the following reasons.
o The types of transmission projects that would be needed to avoid proposing the
use of the Firm Demand interruption under footnote ‘b’ are expected to be high cost,
long lead time Corrective Action projects. Therefore, consideration of the any
necessary approvals from regulatory authorities or governing bodies responsible for
approving the Corrective Action project is a prerequisite and essential to any
discussion or stiputlations regarding disapproval of the use of footnote ‘b’ proposal.
The proposed TPL-002 text for Section III does not include any language to address
this crucial aspect of any footnote ‘b’ approval sipulations.
o The diversity of applicable regulatory authorities and governing bodies, as well as
their justicitional scope or criteria with respect to the approval of interrupt retail
electic service (as well as transmission Corrective Action projects), are too diverse
and complex to be appropriately addressed by proposed Approval stipulations in the

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Yes or No

Question 4 Comment
TPL-002 standard.
If Section III is not removed, then the NSRF suggests the following changes.
o Include the subject of approvals of Corrective Action projects that are necessary to
negate the need for approval of the proposed Firm Demand interruption.
o Replace the criteria regarding the voltage level of the relevant Contingency with
criteria regarding the amount and type of Firm Demand that would be subject to
interruption. The voltage level of the applicable Contingency elements are not
material to impact on the affected load.
o Replace the applicable amount of Firm Demand interruption criteria from 25 MW
to at least 100 MW. There are many radial fed loads that are much geater that 25
MW and there are no stackholder meetings and required approvals for allowing the
loads to be fedd radially (subject to interruption for Category B contingencies) rather
than being network fed. The DOE threshold for requiring formal system event
analysis is 100 MW of load dropping. So, why should the TPL-002 standard required
special approvals to allow less than 100 MW of load be subject to interruption to
assure BES reliability?
o Change the text of “in Year One of the Planning Assessment” to “in the ten year
planning horizon of the Plannign Assessment”. The planning assessments may reveal
that the need to use of Firm Demand interruption will occur in Year 2, Year 3 or
beyond (e.g. when a significant previously unforecast load increase is forecast to
occur before any needed Corrective Action project could be initiated and
implemented).
o The NSRF is concerned that the current wording, “Corrective Action in Year One of
the Planning Assessment” could be interpreted to require an annual stakeholder
process review and approval. The NSRF suggests that the standard drafting team
provide some language regarding a specific period that is expected for reaffiming the
approval of the Firm Demand interruption. A review interval of at least every five
years should provide reasonable business certainty and allow for future transmission

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Yes or No

Question 4 Comment
construction if needed. The specific defined period of review should allow entities to
operate in an effective manner.
The NSRF is also concerned about the condition where approval was granted and
then removed. Would an entity be instantly non-compliant to the TPL standards? If
this is a possibility, the Standard Drafting Team should add a grace period that allows
an entity to credibly construct a project to remain compliant.

American Transmission
Company

No

ATC recommends that Section III be removed for the following reasons.
o The types of transmission projects that would be needed to avoid proposing the
use of the Firm Demand interruption under footnote ‘b’ are expected to be high cost,
long lead time Corrective Action projects. Therefore, consideration of the any
necessary approvals from regulatory authorities or governing bodies responsible for
approving the Corrective Action project is a prerequisite and essential to any
discussion or stipulations regarding disapproval of the use of footnote ‘b’ proposal.
The proposed TPL-002 text for Section III does not include any language to address
this crucial aspect of any footnote ‘b’ approval stipulations.
o The diversity of applicable regulatory authorities and governing bodies, as well as
their jurisdictional scope or criteria with respect to the approval of interrupt retail
electric service (as well as transmission Corrective Action projects), are too diverse
and complex to be appropriately addressed by proposed approval stipulations in the
TPL-002 standard. If Section III is not removed, then ATC recommends the following
changes.
o Include the subject of approvals of Corrective Action projects that are
necessary to negate the need for approval of the proposed Firm Demand
interruption.
o Replace the criteria regarding the voltage level of the relevant Contingency
with criteria regarding the amount and type of Firm Demand that would be
subject to interruption. The voltage level of the applicable Contingency elements

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Yes or No

Question 4 Comment
are not material to impact on the affected load.
o Replace the applicable amount of Firm Demand interruption criteria from 25
MW to at least 100 MW. There are many radially fed loads that are much greater
than 25 MW and there are no stakeholder meetings or required approvals for
allowing the loads to be fed radially. The DOE threshold for requiring formal
system event analysis is 100 MW. So, ATC believes the TPL-002 standard should
not require special approvals to allow less than 100 MW of load to be
interrupted to assure BES reliability. o Change the text of “in Year One of the
Planning Assessment” to “in the ten year planning horizon of the Planning
Assessment”. The planning assessments may reveal that the need to use of Firm
Demand interruption will occur in Year 2, Year 3 or beyond (e.g. when a
significant previously unexpected load increase is forecast to occur before any
needed Corrective Action project could be initiated and implemented).
o ATC is concerned that the current wording, “Corrective Action in Year One of the
Planning Assessment” could be interpreted to require an annual stakeholder process
review and approval. ATC suggests that the standard drafting team provide some
language regarding a specific period that is expected for reaffirming the approval of
the Firm Demand interruption. A review interval of at least every five years should
provide reasonable business certainty and allow for future transmission construction
if needed. The specific defined period of review should allow entities to operate in
an effective manner.

Response: If you have already gotten approval from regulatory bodies in your planning process, then Section III is basically already
accomplished, and carrying out the remaining details should not be burdensome. No change made.
While it may be true that regulatory authorities and governing bodies are diverse and complex, they are representing their area of
responsibility. What may be acceptable in one area, may not be acceptable in another. This is determined by the appropriate
authorities. No change made.
The SDT does not believe approvals from regulatory authorities or governing bodies responsible for approving the Corrective Action
project is a prerequisite or essential. The focus of this portion of the standard is dropping Load and when approval is necessary.
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Yes or No

Question 4 Comment

There is no benefit in including approval of Corrective Actions. No change made.
The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the Contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers, and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load dropping, it should
require approval. No change made.
The data request also showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. No change made
The text regarding Year One of the Planning Assessment just means that approval from the appropriate regulatory bodies is needed
at least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be determined in
the study of a future year or that approval cannot be sought sooner.
The intent of the SDT was that a review must be obtained one time from the appropriate regulatory body. It does not need to be
reviewed again unless the situation changes. The SDT has changed the wording to the following:
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
The proposed TPL-001-2 accommodates this concern regarding circumstances beyond the control of the Transmission Planner or
Planning Coordinator in Part 2.7.3 of Requirement R2.
SERC EC Planning Standards
Subcommittee

No

We recommend using a technical basis for load shedding instead of a Stakeholder
Process. However, if a Stakeholder Process is used, the approval thresholds are
correct. The Stakeholder Process should not even be initiated for less than these
threshold levels.

Southern Company

No

Southern recommends using a technical basis for load shedding instead of a
Stakeholder Process. However, if a Stakeholder Process is used, the approval
thresholds given in the draft seem appropriate. Furthermore, we believe the
Stakeholder Process should not even be initiated for less than these threshold levels.

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Yes or No

Question 4 Comment
Lower amounts of load and lower voltage contingencies do not need to be taken
through a Stakeholder Process.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
ACES Power Member
Standards Collaborators

No

(1) What is the justification for selecting a 300 kV contingency as a threshold for
requiring local regulatory agency approval? What if the planned load shed is only for
1 MW? If a threshold is required, we think it should be based on load size rather than
contingency size?
(2) What is the justification for selecting 25 MW of planned firm load interruption as
a threshold for requiring local regulatory approval? The threshold could be set based
off of the accompanying Section 1600 data request. Since there are likely not many
instances, it could be required for any new instance that exceeds the existing planned
load shed amounts. Thus, the threshold would be set just above existing planned
load interruptions.
(3) A disclaimer should be added to clarify that an entity may still have to seek local
regulatory agency approval per the local regulatory agency’s rules. Nothing in the
NERC standard will change the local regulatory agency’s rules.
(4) What if the local regulatory agency does not want to address the planned load

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Yes or No

Question 4 Comment
shed in the planning time frame? What is the Transmision Planner required to do?
While it is likely a local regulatory agency would be interested in addressing a
planned load interruption, nothing in the NERC or Commission rules can compel a
local regulatory agency to address such matters in a specific time frame.
(5) Bullet 1.a is confusing. Is it intended to say that if two Elements are part of a
contingency and the Elements have different voltage classes, the Element with the
lowest voltage class must exceed the 300 kV threshold? If this is the case, the bullet
needs further clarification because it does not state this clearly.
(6) The first paragraph after section III appears to contradict bullets 1 and 2. Bullets
1 and 2 place contingency and load thresholds on the planned firm load interruption.
However, this paragraph says that the regulatoy body responsible for retail electric
service must approve the planned load shed before it can be used in Year One of the
planning assessment. If the purpose is for the thresholds to apply beyond Year One
and any instance in Year One to require approval, then the language regarding the
thresholds needs to clarify that the thresholds apply beyond Year One only.
(7) We think it is redundant for the Regional Entity to evaluate planned interruptions
of firm load in its footprint. The Planning Coordinator has a wide area view and is
already required to do this for its footprint. The Planning Coordinator already works
with its neighbors to evaluate impacts. Requiring this evaluation by the Regional
Entities is arbitrarily based on historical and political boundaries. Many Planning
Coordinators have views that are broader than the Regional Entity view because they
are in multiple regions. If this evaluation will be required on a regional basis, why
won’t it be required on an interconnection?
(8) The evaluation required by the Regional Entity may be completed before planned
load interruption is approved by local regulatory body. The TP and PC must submit
the data based on their plan before the local regulatory body approves the planned
load interruption. The Regional Entity must complete its evaluation within 45 days of
receiving the information. There is no obligation for the local regulatory body to act
within 45 days. Wouldn’t it make more sense to evaluate the planned load shed after

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Yes or No

Question 4 Comment
it is approved by the local regulatory body?

Response: (1) The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the
Contingency studied. This is based on the belief that Transmission lines 300 kV and above are for bulk power transfers, and lower
voltage lines are more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load shed,
it should require approval even if it is only 1 MW.
(2) The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. No change made.
(3) There is no need for such a disclaimer in a NERC Standard. An entity has to abide by other applicable rules outside of the
standard. No change made.
(4) The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some
of the concerns. If the local regulatory agency does not want to address the planned Load shed, then they are giving their tacit
approval to the Load shedding.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
(5) Yes. For 1.a to apply, the Element with the lowest system voltage level must be 300 kV or above. The SDT believes the wording is
clear. No change made.
(6) The text regarding Year One of the Planning Assessment just means that approval from the appropriate regulatory bodies is
needed at least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be
determined in the study of a future year or that approval cannot be sought sooner.
(7) The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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

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Yes or No

Question 4 Comment

whether there are any Adverse Reliability Impacts caused by the request to utilize footnote ‘b’ for Firm Demand interruption.
(8) No. The planned Load shed should not be reviewed by the local regulatory body unless it has been determined that there are no
Adverse Reliability Impacts.
Bonneville Power
Administration

No

Regarding Section III.2 as stated above, BPA does not support quantitative limits on
planned interruption, as planners generally do not plan the system to interrupt
demand for a single contingency. Setting a quantitative limit would push
transmission planners to plan the system to meet such a limit for a single contingency
in all cases.

Response: The SDT does not agree that setting a quantitative limit would push Transmission Planners to plan the system to meet
such a limit for a single Contingency in all cases. The footnote states that an objective of the planning process should be to minimize
the likelihood and magnitude of Load shed. However, a quantitative limit is needed to ensure that unreasonable amounts of Load
shed are not proposed. No change made.
TVA Transmission Reliability
Engineering & Controls

No

Please see answer to question #1. TVA believes that the requirements of 25 MW as
well as any Bulk contingency over 300-kV is much too burdensome. TVA beleives that
only larger load drops should require a Stakeholder review.

Response: Please see response to Q1.
Arizona Public Service
Company

No

AZPS does not agree that approval by the Regional Entity should be required. Once
the process has been fully vetted by the stakeholders, including the regulatory
authority for retail service, there is absolutely no need for Regional Entity approval.
There would be no adverse affect of non-consequential load tripping on the BES. No
reason for Reginal Entity involvement.

Response: The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order,
is now placed on NERC as the ERO. This change should help to promote continent-wide consistency.

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Yes or No

Question 4 Comment

Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
BrightSource Energy, Inc.
Los Angrles Department of
Water and Power
Deseret Generation &
Transmission Cooperative
California Independent
System Operator
nevada power company dba
nvenergy
PG&E Company
Modesto Irrigation Districtt
Utility System Efficiencies, Inc.

No

While we do not disagree with the intent, it is over-reaching for a NERC Standard to
require action from the applicable regulatory authority or governing body responsible
for retail electric service issues to approval of the use of Firm Demand interruption
under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.
Requiring the Regional Entity to approve the Non-Consequential Load Loss under
footnote b in TPL-002 (Footnote 12 in TPL-001-3) is duplicative and would increase
the work load of the Regional Entities without improving reliability. The TP and PC
are already required to make available to the affected stakeholders, verification that
TPL Reliability Standards performance requirements will be met following the
application of footnote ‘b’ (see Section II.6) and the assessment of potential
overlapping uses of footnote ‘b’ with adjacent planners” (see Section II.8), it is hard
to imagine what type of review and verification is required to show that “there are
no Adverse Reliability Impacts including any potential cumulative effect within the
Regional Entity’s footprint”.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.

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Yes or No

Question 4 Comment

The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
MISO

No

We generally agree with the instances for which approval or interruptions is required,
but do not agree with the requirement to seek regulatory approval.In general, when
the footnote is proposed to be utilized as an interim measure until transmission
facilities can be added or reinforced, regulatory approval must be sought in advance.
Having this requirement in a reliability standard not only is unnecessary, but also
introduces regulatory requirements (which provides no reliability benefit or basis) in
a reliability standard. NERC reliability standards should focus only on BES reliability,
not any regulatory requirements. Section III should therefore stipulate a high-level
requirement for the proposing entity to submit the proposal to the RE for review and
concurrence. Along with the submission, the RE may require the proponent to
include a copy of appropriate regulatory approval (which the entity should have
already obtained). The conditions (1) and (2) for seeking regulatory approval can be
retained, but now become the criteria for seeking review and concurrence by the RE.
Additionally, Attachment 1 requires that the ERO develop a methodology on
evaluation criteria to be published for determining Adverse Reliability Impacts for
approval by the ERO. Planning Assessments are performed on an annual basis. The
Attachment 1 process and ERO methodology may require a lengthy approval process
that must be repeated on an annual basis.

Response: The SDT has modified the footnote to require regulatory authority review rather than approval. This should help alleviate
some of the concerns.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment

or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual assessment if the
process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the parameters have not
changed. If any changes have occurred to the original parameters, these issues must then be addressed in the Stakeholder Process
before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
Essential Power, LLC

No

This solution requires filing with a regulatory body for any extra interruptions. This
seems to be a lot of effort and language for a contingency event that the system is
supposed to be able to handle.

Response: The SDT believes that the stakeholder process is necessary to ensure that Load shed is utilized for single Contingencies
only under limited circumstances. No change made.
Tacoma Power

No

As noted in our response to question 2, regulatory approval is often a slow process
and is not conducive to repeating annually.
Instead of a 25 MW limit, a 300 MW limit that corresponds to the reporting level of
firm demand in EOP-004 is more appropriate.

Response: The SDT has added language to indicate that the Stakeholder Process does not have to be repeated for each annual
assessment if the process has confirmed for a specific project that it is acceptable to curtail a Firm Demand, provided that the
parameters have not changed. If any changes have occurred to the original parameters, these issues must then be addressed in the
Stakeholder Process before that Planning Assessment can be completed.
An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 4 Comment

The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process
threshold at 25 MW. The Order 762 data request showed that there were no utilizations of footnote ‘b’ involving more than 75 MW.
Based on this fact, and after reviewing other aspects of the data, the SDT has set the proposed ceiling on footnote ‘b’ utilization at 75
MW.
Manitoba Hydro

No

The Section III states that regulatory authority approval is required for interruptions
over 25 MW or if voltage level of the contingency is greater than 300 kV. However, a
regulatory authority cannot approve interruption of Firm Demand unless it already
has such jurisdiction that is conferred upon them by legislation. A reliability standard
cannot confer that jurisdiction. Further, the regulator is already part of the proposed
stakeholder group and will have input into the proposal.
The Section III requires the Regional Entity to review the proposed use of Firm
Demand interruption under footnote ‘b’. What impact does it have on the Regional
Entity to necessitate a review, if the stakeholders have already agreed to a process,
TPL Reliability Standards performance requirements have been verified as in Section
II.6, and potential overlapping uses have been assessed with adjacent planners as in
Section II.8. What criteria will the Regional Entity use to make their assessment of
Adverse Reliability Impacts and potential cumulative effects given the above TPL
performance must be met? This requirement can lead to inconsistent decisions
between regions.

Response: The SDT believes that the request is consistent with existing practices and is in line with an appropriate response to the
Order. No change made.
The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Independent Electricity
System Operator

Yes or No

Question 4 Comment

No

We generally agree with the instances for which approvals or interruptions are
required. Approval is to be granted by the Reliability Coordinator or applicable
reliability authority. (1) In general, when the footnote is proposed to be utilized as an
interim measure until transmission facilities can be added or reinforced, regulatory
approval must be sought in advance. Having this requirement in a reliability standard
not only is unnecessary, but also introduces regulatory requirements (which provides
no reliability benefit or basis) in a reliability standard. NERC reliability standards
should focus only on BES reliability, not any regulatory requirements. Section III
should therefore stipulate a high-level requirement for the proposing entity to submit
the proposal to the Reliability Coordinator for review and concurrence. The
conditions (1) and (2) for seeking explicit regulatory approval can be retained, but
now become the criteria for seeking review and concurrence by the applicable
reliability authority.
(2) We suggest deleting Item 1 in the first paragraph (with its a and b bullets) and
just indicating that planned Firm Demand interruption requires approval if it is
greater than 25 MW (or other threshold). Requirements for approval of the use of
Firm Demand interruption should be independent of the voltage level of the
contingency.
(3) We propose deleting the sentence in the second paragraph “In no case can the
planned Firm Demand interruption under footnote ‘b’ exceed ‘x’ MW”. A fixed limit
on the allowable size of Firm Demand interruption can not be technically justified for
the whole continent and each case should be assessed to determine if its impact on
reliability of the bulk transmission system is acceptable or not. The impact of each
case on the affected customers (economic, welfare, etc.) will also be reviewed and
approved by the regulatory authority or governmental body of each jurisdiction and a
“reliability” standard must not impose limits and restrictions pertaining to these
aspects.
(4) The third paragraph proposes that the Regional Entity should review each case of
Firm Demand interruption and verify that there are no Adverse Reliability Impacts.

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Question 4 Comment
We propose instead that the transmission planner or planning coordinator study the
BES performance requirements and the reliability impacts of Firm Demand
interruption, including its correct operation, miss-operation, and the failure to
operate. The transmission planner should then submit a report of this assessment to
the Reliability Coordinator for review and approval.

Response: (1) Regulatory review is not always sought in advance. The SDT believes this review is necessary when the planned Load
shed exceeds either of the thresholds in Section III. No change made.
2) The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the Contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers, and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for Load shed, it should
require approval even if it is only 1 MW. No change made.
(3) The SDT does not agree with this suggestion, as such an important consideration cannot be left open-ended. Order 762 also
pointed out the need for a limit on this threshold value. The Order 762 data request showed that there were no utilizations of
footnote ‘b’ involving more than 75 MW. Based on this fact, and after reviewing other aspects of the data, the SDT has set the
proposed ceiling on footnote ‘b’ utilization at 75 MW.
(4) The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Ameren

No

We do not believe that section III is needed, and particularly if an approval is included
as part of the section I process.
We do not subscribe to dropping Firm Demand (non-consequential load) for single
contingency events, and do not see a need to include a voltage threshold as part of
the contingency requirements. All single contingencies in Category B should be

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Yes or No

Question 4 Comment
applicable.

Response: Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are
included to further define and “put a box” around the situations where first Contingency Load shedding could be employed. Having
the ERO review the application of footnote 12 will provide needed continent-wide consistency.
The proposed TPL Standard (TPL-001-2) makes a distinction in the requirements based on the voltage level of the contingency
studied. This is based on the belief that transmission lines 300 kV and above are for bulk power transfers and lower voltage lines are
more for Load serving. The SDT believes that when a higher voltage line Contingency causes the need for load dropping, it should
require approval even if it is only 1 MW. No change made.
ReliabilityFirst

No

ReliabilityFirst has a major issue/concern with Attachment 1, Section 3 (specifically
the last paragraph regarding approval). This section requires the Regional Entity to
review each proposed use of Firm Demand interruption under footnote 12 in order to
verify that there are no Adverse Reliability Impacts. The paragraph goes on to
require the Regional Entity to make its determinations and evaluation of Adverse
Reliability Impacts using a published methodology approved by the ERO. First, since
the Regional Entity is not a user, owner or operator of the BES, ReliabilityFirst
believes the Regional Entity should not have requirements placed upon them.
Furthermore there is no guidance on what is required to be placed within the
published methodology. ReliabilityFirst believes this verification is outside the
Regional Entity scope as delegated by the ERO. ReliabilityFirst believes that if such
verification by the Regional Entity is required, it should be specifically laid out in the
NERC Rules of Procedure and not an attachment within a standard.

American Electric Power

No

AEP is concerned that not all Regional Entities are the same in regards to their
engineering and planning staff, and is not confident that they would all have the
resources necessary to perform the required analysis. AEP is concerned by any
attempt to require that a Regional Enity adhere to processes and prodecures that
have not yet been established. FERC has made comments in the past regarding
requirements places upon regional entities (RRO), and while this standard does not

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 4 Comment
yet apply, is does indirectly obligate them to rules and procedures not yet
established.

Response: The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order,
is now placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
Consolidate Edison Co. of NY,
Inc.

No

See reply to Question 5

Salt River Project

No

Additional comment from SRP for Q #5.

Response: Please see response to Q5.
City of Austin dba Austin
Energy

No

The 25 MW threshold for Approval of Interruptions of Firm Demand under Footnote
‘b’ is too low. It should be increased to 50 MW because there is an elaborate
Stakeholder process to work through the reliability concerns.

Response: The data request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the
process threshold at 25 MW. No change made.
Lincoln Electric System

No

For item 1(b) in Section III, LES requests that the drafting team clarify why approval
by the regulatory authority for a generator contingency is based on the high-side
voltage of the GSU rather than the generator capacity. LES believes the generator
capacity, rather than the high-side voltage of the GSU, provides a more consistent
basis for determining necessity for approval from the applicable regulatory authority
or governing body.
Additionally, LES asks for further clarification as to whether the steps referenced for

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment
Year One of the Planning Assessment extend to Year Two and beyond.

Response: The SDT disagrees that generator capacity is a better basis for determining the necessity for review. The requirements
within the TPL standards have different performance levels based on a 300 kV voltage threshold for the Contingency. This
distinguishes Facilities generally constructed to transmit power from Facilities used to distribute power to Load centers. The SDT
believes this to be a better basis for determining what is important enough to require review from regulatory authorities. No change
made.
The text regarding Year One of the Planning Assessment just means that review from the appropriate regulatory bodies is needed at
least one year before that Load shed is planned for. This does not mean that the need for dropping Load cannot be determined in the
study of a future year or that review cannot be sought sooner.
LCRA Transmission Services
Corporation

No

See previous comments about use of the term “Firm Demand”.

Response: Please see previous response.
Tri-State Generation &
Transmission Association, Inc.

No

We disagree with the instances for which Approval of Interruptions is required as
proposed by Section III of Attachment I. TPs will develop plans to mitigate BES
performance violations, but those plans may not be able to be constructed in time.
The reason being that the time required to construct a project to mitigate the issues
can take several years. This is due to the need for public input, permitting,
acquisition, and construction. Attachment I does not allow planners to design
temporary mitigation to accommodate real world construction issues, which are
often complex in nature due to competing interests. Attachment I also states that
“Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an
element of a Corrective Action Plan in Year One of the Planning Assessment...” The
need for approval seems burdensome such that it does not allow for temporary
mitigation to meet BES performance criterion while other avenues are explored and
vetted.
The intent of Section III is genuine, but we feel that it is over-reaching for a NERC

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment
Standard to require action from the applicable regulatory authority or governing
body responsible for retail electric service issues to approval of the use of Firm
Demand interruption under footnote ‘b’.
In any case, using 25 MW as the threshold of loss of Non-Consequential Firm Demand
for requiring approval is not realistic. As stated in this questionnaire 25 MW came
from registration limit for generation in the ERO Statement of Compliance Registry
Criteria. It will be a stretch to apply this to load.

Response: The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate
some of the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will
be completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
Section III is not requiring action from the regulatory authority. It requires action from the Transmission Planner or Planning
Coordinator.
The 25 MW threshold came from the Registry Criteria for Load Serving Entities, not from Generator Owners and Operators. The data
request showed that the average value of footnote ‘b’ utilizations was 19 MW. Therefore, the SDT has kept the process threshold at
25 MW. No change made.
Duke Energy

No

Section III is confusing. Are the last two paragraphs of Attachment 1 supposed to be
part of Section III? These paragraphs, when read in combination with the first
paragraph of Attachment 1, seem to say that any time a Firm Demand interruption
using footnote ‘b’ or footnote 12 shows up in the Near-Term Transmission Planning
Horizon, the Stakeholder Process must be invoked. It would seem more reasonable
to invoke the Stakeholder Process only when such interruption occurs in Year One of

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment
the Planning Assessment.

Response: The last two paragraphs are intended to be included in Section III.
The SDT believes it is more appropriate to require the stakeholder process whenever load interruption is planned in the Near-Term
Transmission Planning Horizon. That allows more time for all interested parties to be informed.
Hydro-Quebec TransEnergie

No

For example, in 1a., it is not clear what is meant by "the stated performance criteria
regarding allowances...". Why is it necessary to give this kind of explanation?
In 1b., the use of the term "non-generator step up transformer" is unusual. Suggest
rewording 1b to read:For a generator or generator step up transformer outage
Contingency, the extra high voltage (EHV) limit applies to the BES connected voltage
(high-side of the Generator Step Up transformer). For any other transformer outage
Contingency, the EHV limit applies to the low-side winding (excluding tertiary
windings).

Response: In the context of the complete sentence, the SDT believes that the comment is clear. No change made.
The terminology is consistent with the Board of Trustees approved TPL-001-2. No change made.
NorthWestern Energy
(NWMT)

No

Comments: A NERC Standard should not require action from a regulatory authority to
approve the use of Firm Demand interruption. There is too much diversity in
regulatory authorities over the industry-wide area. This would increase the work load
of the Regional Entities without improving reliability. We suggest removing Section III
of Attachment 1.

Response: The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help
alleviate some of the concerns..
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Yes or No

Question 4 Comment

footnote ‘b’ if either:
Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are included to
further define and “put a box” around the situations where first Contingency Load shedding could be employed. The SDT believes
that an evaluation by the ERO of the potential for adverse system impacts is needed to provide continent-wide consistency.
Therefore, Section III is needed. No change made.
Georgia Transmission
Corporation

No

GTC would appreciate if the SDT could please clarify if the approval of a regulatory
authority or governing body is referring to the Regional Entity.The first sentence in
Section III:”Approval of the use of Firm Demand interruption under footnote 12 by
the applicable regulatory authority or governing body responsible for retail electric
service issues is required if either:...”

Response: No, that sentence refers to regulatory authorities such as a state public service commission.
ISO New England Inc.

No

Section III describes the instances where Approval of Interruptions of Firm Demand
are required under footnote 12. It is not clear whether under Paragraph III.1.a and
Paragraph III.1.b the Transmission Planner is to base the determination on either
contingency or both contingencies i.e. is “and” logic to be applied or is “or” logic
used? Paragraph III.2 requires such approval for interruption equal to or greater than
25 MW, this is a very small amount of load to be required to bring to a stakeholder
approval process for second contingency events. This amount should be increased to
at least 100 MW.
Additionally in Section III, it is not clear who the “regulatory authority or governing
body responsible for retail electric service issues” is. Having this requirement in a
reliability standard not only is unnecessary, but also introduces regulatory
requirements in a reliability standard. NERC reliability standards should focus only on
BES reliability, not any regulatory requirements. The Attachment goes on to state
“The Regional Entity determinations of Adverse Reliability Impacts are to be
evaluated by the Regional Entity through a published methodology approved by the
ERO”. This is essentially a “fill in the blank” requirement and makes it necessary to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment
comment and approve the footnote attachment without the benefit of reviewing a
proposed methodology.

Response: Section 3 clarifies the criteria for the application of footnote 12. Items 1 and 2 are included to further define and “put a
box” around the situations where first Contingency Load shedding could be employed; as such, they are an “or” requirement and the
‘or’ has been added to the Attachment.
The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
The regulatory or governing body should be known by the entity who plans to use footnote 12.
South Carolina Electric and
Gas

No

See response to question #1

Response: Please see response to Q1.
Electric Reliability Council of
Texas, Inc.

No

If non-consequential load shedding is allowed for single contingency conditions, as
discussed above, it should be based on objective critieria. As such, there is no need
for the proposed stakeholder process, including the Section III instances requiring
regulatory approval. As with the other stakeholder process sections, that section
should be eliminated.

Response: Industry and the NERC BOT have approved the use of a Stakeholder Process to address the concerns with the original
footnote ‘b’ and with footnote 12 in TPL-001-2. The SDT is now attempting to address FERC’s concern expressed in their Remand
Order 762 that NERC’s proposed Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for
planned Load shed in a single Contingency provided that the plan is documented and alternatives are considered in an open and
transparent process, is vague, unenforceable, and not responsive to the previous Commission directives on this matter. The draft
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment

posted for comment adds detail and specificity to the already-approved approach. The SDT does not believe it appropriate to move
away from the industry and BOT approved Stakeholder Process approach. No change made.
Section 3 directly addresses concerns raised by FERC contained in the remand of the TPL standard. Items 1 and 2 are included to
further define and “put a box” around the situations where first Contingency Load shedding could be employed. The SDT believes
that an evaluation by the ERO of the potential for adverse system impacts is needed to provide continent-wide consistency.
Therefore, Section III is needed. No change made.
San Diego Gas & Electric

No

Public Utility District No. 1 of
Snohomish County

No

Response: Without specific comments, the SDT is unable to respond.
Orlando Utilities Commission

Yes

Comment #1: The maximum threshold should be in the Footnote, not in the
Attachment.
Comment #2: I think the role identified for the Regional Entity is appropriate.
Comment #3: I like the concept that regulatory approval is not required until year
one. However I think either the ordering of language or the formatting needs to be
changed to make it clear that the year one applies to only those that need regulatory
approval. Maybe change the section to read... "Section IIIFirm Demand
Interruptions under footnote 'b' that meet either or both of the criteria below are
required to have approval by the applicable regulatory authority or governing body
responsible for retail electric service issues. The regulatory approval is required prior
to the use of that remedy in Year One of a Corrective Plan in the Planning
Assessment. (Existing 1 & 2)(Existing RE Review)

Response: The maximum threshold is the last sentence of the footnote, and is also cited in Section III of the Attachment. No change
made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 4 Comment

The SDT agrees and has deleted the Regional Entity role in this process. The oversight role, which is required in the Order, is now
placed on NERC as the ERO. This change should help to promote continent-wide consistency.
Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
The SDT has modified the footnote to require regulatory authority review, rather than approval. This should help alleviate some of
the concerns. An entity wishing to utilize footnote “b” should start the review process at an appropriate time so that it will be
completed by the required date.
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective Action Plan in Year One of the
Planning Assessment, the Transmission Planner or Planning Coordinator must assure that the applicable regulatory authority
or governing body responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ if either:
LCEC (Lee County Electric
Cooperative

No comment as although we are a Firm Demand customer of another entity, we have
no Firm Demand / Load customers and therefore would not perform the Stakeholder
Process

CPS Energy

Yes

Idaho Power Co.

Yes

Nova Scotia Power

Yes

Response: Thank you for your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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5.

If you have any other comments on this Standard that you haven’t already mentioned above, please provide them here.

Summary Consideration: Many commenters proposed changes to the applicable planning events for which footnote 12 applies in
the new proposed TPL-001-2a standard. The SDT clarifies that the planning events for which footnote 12 are applicable were
already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011) in its consideration of TPL-001-2. The proposed
changes are outside the scope of this project, which aims to clarify the stakeholder approval process.
Some commenters indicated confusion surrounding changes made to footnote 12 and Attachment 1 in the proposed TPL-001-2a
standard in regard to the use of the term Firm Demand interruption. The SDT acknowledges that the references to Firm Demand
Interruption should reference Non-Consequential Load Loss in footnote 12. The SDT has made revisions to the TPL-001-2a Footnote
12 and Attachment I to show these changes.
Some commenters continue to weigh-in on FERC’s jurisdiction in regard to continuity of service to Load. FERC Order 762, beginning
at Paragraph 23, discusses FERC’s position on jurisdictional issues. This topic was well-vetted in the development of TPL-001-2, and
FERC’s subsequent NOPR and is beyond the scope/authority of this drafting team.
The following change was made due to industry comments:
Effective date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first calendar quarter, 60
months after approval by applicable regulatory authorities. In those jurisdictions where regulatory approval is not required, the
effective date will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other requirements remain in effect per previous
approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.
Attachment 1 – Section I, last paragraph: An entity does not have to repeat the stakeholder process for a specific application of
footnote ‘b’ utilization with respect to subsequent Planning Assessments unless conditions spelled out in Section II below have
materially changed for that specific application.
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority or governing
body responsible for retail electric service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand
interruption.

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NorthWestern Energy
(NWMT)

Question 5 Comment
Comments: Footnote 12 should be added to Category P2 Single Contingency Event
2, Bus Section Fault, and to Category P2 Single Continency Event 3, Internal Breaker
Fault , for EHV in the Non-Consequential Load Loss column.

Response: The planning events for which footnote 12 are applicable within the proposed TPL-001-2 standard were already vetted by
industry and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
ACES Power Member
Standards Collaborators

(1) The standard needs to allow more flexibility regarding the use of planned load
shed to address transmission performance issues in the planning horizon. It needs to
recognize that these planned load shedding events may only be preliminary decisions
for addressing problems that are several years away. If there is little chance that the
planned shed load will ever be relied upon in the operating time horizon, there
should be much less stringent requirements. For instance, if a PC or TP relies on
planned load shed for year five of the planning horizion but year one does not utilize
the planned load shed, they have four years to develop another solution. Why
should great effort and resources be expended in year five when another solution will
likely be developed?
(2) This standard does not consider if the local regulatory body will act in time to
approve the use of planned Firm Demand interruption. We believe the standard
needs to consider that the Planning Coordinator and Transmission Planner may not
be able to control the timelines of local regulatory agencies. As long as the PC and TP
have done their part by submitting the data, they should be able to rely on the
planned Firm Demand interruption until the local regulatory body acts. If the
planned Firm Demand interruption is not approved, then the TP and PC should be
given more time to address the transmission performance deficiency.
(3) Several terms are used for the use of planned load shed. Non-consequential load
loss and Firm Demand interruption are two examples. We suggest using one term
consistently throughout the standard.

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Response:
(1) For reasons similar to those raised by the commenter, the SDT limited Attachment 1 as being applicable only to planned use of
Firm Demand interruption in the Near-term Planning Horizon (Years 1-5), recognizing that plans may change. The SDT believes it
is appropriate to require the stakeholder approval process in the Near-term Planning Horizon. The Near-term Planning Horizon
plans should become more stable over those identified on the Long-term Planning Horizon. No changes made.
(2) The SDT has clarified the language concerning regulatory approval to show that review is what is actually required. Review by the
regulatory authority or governing body responsible for retail electric service issues is only required in certain instance of planned
Firm Demand interruption and if planned for use in Year One of the Near-Term Transmission Planning Horizon. When required,
the indicated review must be obtained before it can be part of a Corrective Action Plan. Until such review, the planner would
need to consider and list alternate Corrective Action Plans within its assessment. The SDT has also clarified that such reviews
need only be done once, unless material changes have taken place. The SDT believes that these changes should alleviate the
majority of lead-time concerns, although an entity should always build sufficient time for the process to play out into its planning
cycle.
(3) An entity does not have to repeat the stakeholder process for a specific application of footnote ‘b’ utilization with respect to
subsequent Planning Assessments unless conditions spelled out in Section II below have materially changed for that specific
application.
(4) Once assurance has been received that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
(5) The terms used are appropriate since the existing FERC-approved TPL standards and the proposed TPL-001-2 (NERC Board of
Trustees approved 8/4/2011) use differing terminology for the common topic (planned load shed) of both footnote ‘b’ (Firm
Demand Interruption) and footnote 12 (Non-Consequential Load Loss). The SDT acknowledges that the reference to Firm
Demand Interruption should reference Non-Consequential Load Loss. The SDT has made appropriate revisions to proposed TPL001-2a, Attachment I.
Independent Electricity
System Operator

(1) We’d like to reiterate our support for allowing load interruption for a single
contingency with sufficient review/oversight and under acceptable conditions,

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including no adverse impact on the reliability of the bulk electric system. The
reliability aspects (BES performance requirements) should be reviewed/approved by
the Reliability Coordinator. However, issues pertaining to economics or externalities
which may not be directly reliability-related are always available for review and
debate by the stakeholders via the regulatory processes and subject to approval by
the regulatory authority of each jurisdiction (particularly those in Canada and
Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2 approved
by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow
the same load interruption that is allowed for the related P1 contingency. Table 1
currently does not allow any load to be interrupted for an EHV single contingency if
the primary circuit breakers fail to clear the fault (Category P4, “Fault plus stuck
breaker”). But if load X is allowed to be interrupted for a single EHV transmission line
contingency (Category P1), it should be allowed to interrupt the same load X if the
primary breaker fails and the fault is cleared by other breakers. Similarly, if the same
breaker has an internal fault or there is a fault on the same bus section (Category P2)
or there is a failure of a relay (Category P5), which results in the loss of the same EHV
transmission line, it should be allowed to interrupt the same load X.
(3) We suggest that NERC Standards and their requirements should focus on what is
the anticipated outcome rather than how to achieve them. Accordingly, we believe
that the focus of the foot note ‘b’ should be that interruption of load must not
adversely impact the reliability of the interconnected BES because reliability of supply
to load and/or supply continuity is mandated by the jurisdictional authority.
(4) We submit that the scope of NERC’s mandatory standards does not extend to
assessing or setting requirements for non-jurisdictional entities, unless such facilities
are necessary for the operation of the interconnected BES or have an adverse impact
on its reliability. For Canadian entities there are regulatory requirements and
processes under the purview of the relevant regulatory authorities that we believe
are adequate. Accordingly, customer interests are protected and are not subject to

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unilateral decisions of the transmission planner. In all cases, steps are taken at the
planning, design, and operations stages of system development such that nonconsequential Firm Demand interruption would not adversely impact the BES and the
affected customer has been given the opportunity to avail themselves of other
options under the transmission development rules in the relevant jurisdictions.
(5) The requirements of the footnote (including attachment) will amount to a
mandate to construct additional transmission which is inconsistent with Section 215
(i) (2) of the US Federal Power Act which specifically does not authorize the ERO “to
order the construction of additional generation or transmission capacity or to set and
enforce compliance with standards for adequacy or safety of electric facilities or
services.
(6) We suggest that NERC should not include and/or address load reliability or load
supply continuity requirements within the BES Reliability Standards. In Canada, these
requirements and approvals are with relevant reliability or regulatory authority. If
NERC feels obligated to include such requirements for load reliability issues in US,
then we propose that non-jurisdictional entities must be exempted from these
requirements similar to the provisions in NUC 001.
(7) The proposed implementation plan conflicts with Ontario regulatory practice
respecting the effective date of the standard. It is suggested that this conflict be
removed by appending to the implementation plan wording, after each “applicable
regulatory approval” in the Effective Dates Section A5 of both draft standards, to the
following effect: “, or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities.”

Response:
(1) The SDT thanks you for your general support of the proposed stakeholder process. It’s anticipated that the Reliability
Coordinator will be a stakeholder participant and could raise any concerns they believe are warranted. The SDT appropriately
set the BES reliability approval to the Regional Entity with ERO backstop authority per FERC Order 762, Par. 55. Paragraph 55
states in part: “NERC and the Regional Entities provide both objectivity in the decision-making process as well as the necessary
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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reliability-focused expertise.” No change made.
(2) The planning events for which footnote 12 is applicable within the proposed TPL-001-2 standard were already vetted by industry
and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project which
aims to clarify the stakeholder approval process. No change made.
(3) The proposed Attachment 1 achieves the view stated by the commenter. BES Reliability is assured by the Regional Entity and
ERO where warranted. The approval by the regulatory authority or governing body responsible for retail electric service issues
addresses continuity of service to end-use Load. No change made.
(4) The proposed Attachment 1 process appropriately sets governance for both the ERO and Regional Entities to ensure no Adverse
Reliability Impact of the BES. If existing processes are already in place to ensure end-use Loads are appropriately protected,
those processes may be utilized to fulfill the Attachment I obligations. No changes made.
(5) FERC Order 762, beginning at Paragraph 23 discusses the FERC’s position on jurisdictional issues that are raised by the
commenter. This topic was well-vetted in the development of TPL-001-2 and FERC’s subsequent NOPR and is beyond the
scope/authority of this drafting team. No changes made.
(6) There are no current exemptions in the TPL standards, and it is not within the scope of the SDT to introduce any at this time. No
change made.
(7) The SDT has revised the effective date language to reflect the latest guidance received from the Standards Committee.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first calendar quarter, 60 months
after approval by applicable regulatory authorities. In those jurisdictions where regulatory approval is not required, the
effective date will be the first day of the first calendar quarter, 60 months after Board of Trustees adoption or as
otherwise made effective pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’
becomes effective.
MISO

(1) The process described in Attachment 1 may be more suited for inclusion in the
Rules of Procedure, similar to the process required for seeking BES facility exceptions.
We urge the SDT to consider moving Attachment 1 into a proposed RoP instead of

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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stipulating it in the standard.
(2) It may be more appropriate to develop a Standards process that covers the
technical aspects of using a footnote 12 and leave regulatory review and approval to
FERC and State agencies.

Response:
(1) The SDT respectfully disagrees with the commenter. Inclusion of the Attachment 1 text within the Rules of Procedure might be
appropriate for consideration if the process had wide impact on multiple NERC reliability standards. As such, since limited to use
within the TPL standards, its inclusion directly within the TPL standard(s) is applicable. No changes made.
(2) The SDT believes the Attachment 1 process strikes the appropriate balance of regulatory oversight. BES Reliability is assured by
the Regional Entity and ERO where warranted by assessing any Adverse Reliability Impact. The regulatory authority or governing
body responsible for retail electric service issues addresses continuity of service to end-use Load. No change made.
Deseret Generation &
Transmission Cooperative
Salt River Project
Los Angrles Department of
Water and Power
Tri-State Generation &
Transmission Association, Inc.
nevada power company dba
nvenergy
PG&E Company

: The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it
is applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV in P1 is of no value.
The footnote 12 should be added to Category P2 Single Contingency Event 3 Internal
Breaker Fault for EHV in the Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a

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bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore
the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 3The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.

Hydro-Quebec TransEnergie

Footnote 12 is not applied to Categories P4 and P5, which would include a EHV stuck
breaker or failure of a non-redundant relay for a Multiple Contingency. The Load loss
restriction for the contingencies listed in P4 and P5 is more restrictive than for the
loss of a EHV double circuit line. Statistics indicate that the contingencies presented
in P4 and P5 are less frequent. HQT requests that Footnote 12 should also be used for
P4 and P5 contingencies for EHV. Even though considering Firm Demand
interruption in planning might not be common practice, HQT agrees that the
proposed Footnote 12 should maintain such a possibility.

Response: The planning events for which footnote 12 are applicable within the proposed TPL-001-2 standard were already vetted by
industry and the NERC Board of Trustees (approved on 8/4/2011). The proposed changes are outside of the scope of this project,
which aims to clarify the stakeholder approval process. No change made.
Essential Power, LLC

As written, this change is complex and will be difficult to execute without additional
turmoil on the planning end and offers limited clarification. Some additional issues to
consider;1. Should this level of contingency allow isolation/removal of load or
generation if not part of the outage?
2. Should additional generation be allowed to be removed, again considering the
contingency level?

Response: 1. The binary question of applicable use was well vetted during the development of both the revised footnote ‘b’ and
footnote 12. It is clear that some use, appropriately bounded, is the desire of industry and FERC. The SDT believes the proposed
Attachment 1 provides the clarity sought by FERC in its remand of footnote ‘b’ and that the process is reasonable in its approach. No

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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changes made.
2. Generation is not addressed in footnote ‘b’. No change made.
Public Utility District No. 1 of
Snohomish County

Comments: SNPD generally disagrees with the draft process that has been
developed, and notes that infrequent interruption of small amounts of nonconsequential load under limited conditions that does not negatively impact a
neighboring TOP is not a reliability issue. Instead it is a cost of service and customer
service matter best left to the local and state regulatory bodies. The time and
resources spent on this issue at the national level diverts scarse resources and
attention from more important efforts that might actually benefit the reliability of
the BES.
SNPD supports the Pacificorp Revision of TPL-002 footnote ‘b’ and TPL-001 footnote 1
Comments- The proposed revisions will require regulatory approval for interruptions
of firm demand under TPL-002 footnote b or TPL-001 footnote 12 if the voltage level
of the contingency is greater than 300 kV with certain sub-conditions or if the
planned interruption of firm demand under these footnotes is greater than or equal
to 25 MW. The 2011 peak winter and summer loads in the Western Electricity
Coordinating Council (WECC) region were 131,471 and 152,211 MW respectively.
Total installed generation is 229,189 MW. There are 120,385 miles of AC
transmission lines 100 kV and above, and of that total, 31,138 miles of AC
transmission lines are operated at voltages above 300 kV. There are 1,744 miles of
DC transmission lines.The proposed revisions would add considerable process and
documentation for any interruptions, and will require regulatory approval if the
interruption is greater than 25 MW. This is 0.016 percent of the WECC peak load.
The planning standards already require Category B1 contingencies to be considered
which result in the loss of a single generator since individual generator units range in
size up to more than 1000 MW. Since these contingencies are routinely studied, it is
very, very difficult to imagine that the loss of 25 MW or more of firm demand under
TPL-002 footnote b or TPL-001 footnote 12 is so critical to the reliability of the BES
that it deserves not only a lengthy footnote, but a two page attachment detailing a

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complex and lengthy process detailing requirements public meetings, procedures for
questions, specifications for documentation, and even a dispute resolution process.
As this is not a BES reliability issue, any action regarding potential curtailments of
local loads should occur at the local level where the cost and benefit of
improvements can be properly assessed.
The recent blackout that left 2.7 million
customers in Southern California, Arizona and Baja California without power was not
due to planned or controlled interruption of electric supply where a single
contingency occurs on a transmission system. SNPD is not aware of any regional
disturbances or cascading events that were due to planned or controlled
interruptions of electric supply where a single contingency occurred on a
transmission system. As these proposed requirements could be removed from the
Reliability Standards with little or no effect on reliability and would, if anything,
increase the efficiency of the ERO compliance program, the proposed limitations on
curtailment of firm demand under TPL-002 footnote b or TPL-001 footnote 12 should
be removed.

Response: The feedback offered is largely aimed at FERC’s jurisdictional issues in regard to continuity of service of end-use Load.
FERC Order 762, beginning at Paragraph 23, discusses the FERC’s position on jurisdictional issues that are raised by the commenter.
This topic was well-vetted in the development of TPL-001-2 and FERC’s subsequent NOPR and is beyond the scope/authority of this
drafting team. No changes made.
In regard to support offered for the Pacificorp proposal, we direct the commenter to view the SDT response to Pacificorp comments.
Tacoma Power

FERC order 762 states that "to plan for the loss of firm service at the fringes of
various systems would be an acceptable approach.” The newly defined contingency
P2.1 requiring analysis of open ended line sections should allow load shedding of the
load on the line section as suggested in the FERC order.

Response: As P2.1 already includes footnote 12, the SDT is assuming that you are supporting the SDT position and thanks you for
your support.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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San Diego Gas & Electric

Question 5 Comment
In FERC Order 762, FERC rejected NERC’s footnote (b) and urged “...NERC to develop
modifications responsive to the Commission’s directives in Order No. 693 and our
concerns set forth in this final rule.” The NERC SDT has done little to address FERC’s
concerns and instead has resubmitted the same document with additional language.
Order 693 directed NERC to develop modifications to TPL-002-0, which clarify
footnote (b). As redrafted, footnote (b) does not address FERC’s concerns. For
example, footnote (b) continues to use the term “Firm Demand,” which describes all
forms of demand whether served by the faulted element or not. On the contrary,
“consequential load loss” is load, which is removed as a result of a fault. Clearly,
these are different concepts and the new language does not comply with FERC’s
directive. FERC’s position has been that non-consequential load loss through load
shedding shall not be allowed as an exception to TPL-002-0. Also, FERC has stated
that the interruption of Firm Transmission not be allowed as an exception. But,
Footnote (b) continues to say, “Curtailment of firm transfers is allowed ...”. Another
inconsistency. Beyond the differences between what FERC directed NERC to do and
what NERC did, as written, footnote (b) would introduce “stakeholder interests” into
tranmission reliability even if those interests do not promote reliability. The TPL
standards identify the Planning Authority and Transmission Planner as the entities
responsible for meeting the standards and makes no mention stakeholders. To meet
the reliability objectives of the standard, the Planning Authority and Transmission
Planner are subject to Measures and the Compliance Monitoring Process. In FERC
Order 762, FERC determined “...that openness and transparency do not alone ensure
bulk electric system performance criteria will be met...” and was “...not persuaded
that developing technical criteria is unachievable.” Although FERC does not disagree
with adding a stakeholder process, clearly, they do not endorse one and prefer a
technical approach to creating the exception under footnote “b”.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single

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Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Consolidate Edison Co. of NY,
Inc.

Planned interruptions of Firm Demand in response to a Single Contingency (as
directed in Footnote b of TPL-002 Table 1, is not an acceptable corrective action to
mitigate reliability issues on the BES system. The Interconnected System should be
designed and operated with enough transfer capacity to be able to withstand, at a
minimum, a single contingency event without service interruptions to customer load.
Systems must be designed and operated so that the impact of any single contingency
can be mitigated by re-dispatching available system resources without the need to
implement load shedding.

Response: The binary question of applicable use was well-vetted during the development of both the revised footnote ‘b’ and
footnote 12. It is clear that some use, appropriately bounded, is the desire of industry and FERC. The SDT believes the proposed
Attachment 1 provide the clarity sought by FERC in its remand of footnote ‘b’ and that the process is reasonable in its approach. No
changes made.
Manitoba Hydro

Please clarify if an entity must set up a stakeholder process if Firm demand
interruption is not used as an element of the Corrective Action Plan. As I understand
it, the footnote b in TPL 002 will be replicated in the other relevant TPL standards
once it is approved. When it is included in the other TPL standards, will it be
customized to each standard, or will it appear exactly the same in each standard?
Footnote 12 of TPL-001 as currently drafted seems a bit disjointed or incomplete - i.e.
its referring to Non Consequential Load Loss and then it refers you to an Attachment
for the calculation of Firm Demand interruption without providing a connection

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between the two concepts .

Response: A process would only be required if an entity allows or intends to utilize planned Load shed to meet the performance
requirements for single Contingency (N-1) events. The commenter is correct that the final footnote ‘b’ and Attachment 1 will be
replicated in the other currently-enforceable TPL standards – TPL-001, TPL-002, TPL-003 and TPL-004. The SDT acknowledges that
the references to Firm Demand Interruption should reference Non-Consequential Load Loss. The SDT has made revisions to the TPL001-2a Footnote 12 and Attachment I to show these changes.
TVA Transmission Reliability
Engineering & Controls

Please see answer to question #1. TVA beleives that only load drops of higher
magnitudes go thru the Stakeholder and regulatory review.

Response: Please see response to Q1.
BrightSource Energy, Inc.
Utility System Efficiencies, Inc.

The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is
applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV inconsistent with P1.The footnote 12 should
be added to Category P2 Single Contingency Event 3 Internal Breaker Fault for EHV in
the Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a
bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore

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the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 2The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.
The new definition of Non-consequential Load Loss compared to the last version
seems to have deleted the reference to Loads that may be lost during transient
conditions due to under-frequency load shedding (UFLS), while the reference to Load
Loss due to under-voltage load shedding (UVLS) is retained. As a result Load Loss due
to UFLS would be part of Non-consequential Load Loss, and will not be allowed under
single contingency. Because UFLS may also be triggered during transient simulations,
please change the definition for Non-consequential Load Loss to read:”NonConsequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load or frequency
sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.”It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting
steady state reliability requirements. Therefore, in Table 1, please change headernote “i” to read:”The response of voltage sensitive Load and Frequency 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.”

Response: 1 & 2. The SDT disagrees that the use of Footnote ‘b’ between P1 and P2 for EHV is inconsistent. The SDT believes that
the system should be planned so that a fault on an EHV bus section or an internal fault on a non-bus-tie EHV breaker should not
require planned Load loss to resolve system performance issues. The planning events for which footnote 12 is applicable within the
proposed TPL-001-2 standard were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011). The
proposed changes are outside of the scope of this project, which aims to clarify the stakeholder approval process. No change made.
3. The definitions have not been revised, since the standard was approved by the NERC Board of Trustees and changes to those
definitions are not in the scope of this project. No change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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California Independent
System Operator

Question 5 Comment
The application of footnote 12 in TPL-001-3, Table 1 is inconsistent for EHV where it is
applied for single contingency events in Category P1, but not for fault events in
Category P2.Under Category P2 Single Contingency Event 3 Internal Breaker Fault no
Non-Consequential Load Loss is allowed for EHV, that is to say footnote 12 is
conspicuously absent. Every Event in Category P1 Single Contingency must be cleared
with a breaker, and every breaker must meet the Internal Breaker Fault requirement
of Category P2 Single Contingency Event 3. Because the performance requirements of
the P2 Internal Breaker Fault must be met for EHV without the benefit of footnote 12,
the appearance of footnote 12 for EHV in P1 is of no value.The footnote 12 should be
added to Category P2 Single Contingency Event 3 Internal Breaker Fault for EHV in the
Non-Consequential Load Loss column.
Also, a similar difficulty exists for Category P2 Single Contingency Event 2 Bus Section
Fault where no Non-Consequential Load Loss is allowed for EHV. Where bus sections
connect an element (Generator, Line, Transformer, Shunt Device) to one or two
breakers the bus section fault will remove the element from service. Every EHV Event
that includes footnote 12 in Category P1 Single Contingency that are connected by a
bus section to breakers must also meet the requirements of Category P2 Single
Contingency Event 2 Bus Section Fault which does not include footnote 12. Therefore
the omission of footnote 12 in the breaker internal fault event is "inconsistent with"
the P1 event and we suggest adding footnote 12 to the P2 Event 3The footnote 12
should be added to Category P2 Single Contingency Event 2 Bus Section Fault for EHV
in the Non-Consequential Load Loss column.
The process described in Attachment 1 may be more suited for inclusion in the Rules
of Procedure, similar to the process required for seeking BES facility exceptions. We
urge the SDT to consider moving Attachment 1 into a proposed RoP instead of
stipulating it in the standard.

Response: 1 & 2. The SDT disagrees that the use of footnote ‘b’ between P1 and P2 for EHV is inconsistent. The SDT believes that the
system should be planned so that a fault on an EHV bus section or an internal fault on a non-bus-tie EHV breaker should not require

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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planned Load loss to resolve system performance issues. The planning events for which footnote 12 is applicable within the
proposed TPL-001-2 standard were already vetted by industry and the NERC Board of Trustees (approved on 8/4/2011). The
proposed changes are outside of the scope of this project, which aims to clarify the stakeholder approval process. No change made.
3. The SDT disagrees that the attachment should be moved to the NERC Rules of Procedures. Inclusion of the Attachment 1 text
within the Rules of Procedure might be appropriate for consideration if the process had wide impact on multiple NERC reliability
standards. As such, since limited to use within the TPL standards, its inclusion directly within the TPL standard(s) is applicable. No
changes made.
Georgia Transmission
Corporation

The current draft for Requirement 5 (R5) of the NERC Standard TPL-001-3 Draft 1
reads as follows:”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.”GTC has the
following comments regarding TPL-001-3, R5:If the responsible entity has criteria for
transient voltage response, along with criteria for acceptable system steady state
voltage (including a pre-contingency high and low voltage limit, and a postcontingency high and low voltage limit), then having a steady state post-contingency
voltage deviation criteria does not affect the reliability of the bulk electric system
(BES). If the system response to a disturbance were to violate either the transient
response criteria, or the steady state maximum/minimum voltage criteria, there is
potential for loss of integrity of the BES. There is little to no potential for a loss of
system integrity due soley to a violation of the steady state voltage deviation criteria.
Therefore, Georgia Transmission Corporation requests that R5 not include a
requirement to have criteria for post-Contingency voltage deviations.

Response: Requirement R5 requires the Transmission Planner and the Planning Coordinator to have established voltage criteria for
their system. This set of criteria is necessary to ensure that the planners are evaluating the voltage excursions (transient and steady
state) against their performance criteria. The standard requirements have not been revised since the standard was approved by the
NERC Board of Trustees, and changes to those requirements are not in the scope of this project. No change made.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Salt River Project

Question 5 Comment
The new definition of Non-consequential Load Loss compared to the last version
seems to have deleted the reference to Loads that may be lost during transient
conditions due to under-frequency load shedding (UFLS), while the reference to Load
Loss due to under-voltage load shedding (UVLS) is retained. As a result Load Loss due
to UFLS would be part of Non-consequential Load Loss, and will not be allowed under
single contingency. Because UFLS may also be triggered during transient simulations,
please change the definition for Non-consequential Load Loss to read:”NonConsequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load or frequency
sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.”It is also understood that load loss due to UVLS or UFLS or load that are
disconnected from the system by customer equipment are not to be used in meeting
steady state reliability requirements. Therefore, in Table 1, please change headernote “i” to read:”The response of voltage sensitive Load and Frequency 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.”

Response: The definitions have not been revised since the standard was approved by the NERC Board of Trustees, and changes to
those definitions are not in the scope of this project. No change made.
MRO NSRF

The NSRF has concerns that over regulation of footnote “b” or “12” could cause lost
opportunities for legitimate growth. An example condition would be the
development of a large load in a relatively weak transmission area. Many times new
large loads need open undeveloped areas to locate. Without the footnote “b” or
“12” option, could an entity be forced to turn away legitimate load growth? The key
being that an entity could serve the new large load under normal conditions with
easy quick upgrades, but would need 5 - 7 years to construct additional transmission
to meet N-1 conditions? Therefore the entity would need to turn away new growth
because of over regulation on footnote “b” or “12”.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Response: The SDT does not believe that the proposed revision to footnote ‘b’ (or footnote 12) will restrict an entity’s ability to serve
new Load. The SDT has attempted to find a balance between being overly prescriptive and allowing entities the tools they need for
planning purposes while responding to the remand from FERC. No change made.
LCRA Transmission Services
Corporation

The primary objection to Footnote 12 is twofold:1. Application to the P3 contingency.
This contingency is a Category C contingency under the current NERC TPL-003
standard and allows for load shedding. Thus, the proposed standard revision is a
significant and substantial increase in the reliability standard.
2. Use of the term “Firm Demand” as opposed to “Non-Consequential Load Loss.” The
NERC Glossary defines Firm Demand as “That portion of the Demand that a power
supplier is obligated to provide except when system reliability is threatened or during
emergency conditions” and Demand as “The rate at which electric energy is delivered
to or by a system or part of a system, generally expressed in kilowatts or megawatts,
at a given instant or averaged over any designated interval of time.” Thus
interruption of Firm Demand may not result in Non-Consequential Load Loss. Therm
“Firm Demand” should be replaces with “Non-Consequential Load Loss.”

Response: 1. Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
2. The SDT determined that it was appropriate to maintain the existing headers in the existing TPL standards and begin using “Non-

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Consequential Load Loss” with the new TPL-001-2. No change made.
Electric Reliability Council of
Texas, Inc.

The SDT is not required to utilize the stakeholder approach by Order 762 or any other
relevant FERC orders. FERC merely provided guidance as to how the rejected
proposal could be improved. However, if the SDT elects to pursue an exception
process, such exceptions should be based on objective criteria, and the process
should be external to the NERC Reliability Standards (e.g. in the Rules of Procedure).
In Order 693, FERC directed NERC to clarify footnote (b) to prohibit shedding firm
load except for consequential load loss (Order 693 at PP 1773, 1794 and 1797). In a
related compliance order, FERC reaffirmed its position. (130 FERC ¶ 61,200 (March
18, 2010) at PP 8-10 (Compliance Order)) In a subsequent order, FERC clarified that
its Order 693 directive did not preclude consideration of specific comments related to
planning the system based on load shedding at the “fringes” of a system. (131 FERC
¶ 61,231 (June 11, 2010) at P 21 (Clarification Order)) FERC held that regional
variances for case-specific circumstances or a case-specific exception process to plan
for the loss of firm service “at the fringes of various systems” would be acceptable.
(131 FERC ¶ 61,231 (June 11, 2010) at P 21 (Clarification Order)) However, FERC
also stated that it viewed the basis for such exceptions as economic, not reliability,
with the justification being that it was not economic to invest in the bulk electric
system to serve all non-consequential load customers under some single contingency
conditions. (Order 693 at P 1792) FERC made clear that any such regional differences
or case specific exception processes cannot reflect the lowest common denominator,
and, they must be technically justified, and such justification must be strong.
(Clarification Order at P 21. See also Order 693 at P 1794) This is consistent with
FERC’s position that this is a matter of “fundamental issue of transmission service”.
(Order 693 at P 1793) In recognizing that meeting firm demand under single
contingency conditions is fundamental to transmission service, FERC noted that
NERC’s definition of firm transmission service is the "highest quality (priority) service
offered to customers...that anticipates no planned interruption.” (Order 693 at P
1793)Against this background, NERC filed revisions to footnote b that allowed
transmission plans to shed non-consequential load under single contingency

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment
conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, (139 FERC ¶ 61,060 (April 19, 2012))
FERC rejected the approach proposed by NERC and provided guidance on acceptable
approaches to footnote b. However, FERC did not endorse or mandate any particular
approach. Rather, it merely urged “NERC to develop in a timely manner an
appropriate modification that is responsive to the Commission’s directives in Order
No. 693 and our concerns set forth in this Final Rule.” (Order 762 at P21) FERC stated
that in order for any such proposal to have merit, it must be technically justified and
must not reflect the lowest common denominator.As discussed, the proposed
stakeholder approach is not appropriate for NERC Reliability Standards. The SDT
should abandon that approach and consider simple revisions to footnote b that
reference a case by case exception process based on objective criteria that is external
to the NERC Reliability Standards (e.g. Rules of Procedure). Alterantively, it should
develop revisions to the continent-wide standards that clarify that non-consequential
load shedding is not generally permitted for single contingency conditions, but,
consistent with FERC’s orders, exceptions could be established pursuant to regional
rules based on the need/appropriateness in a particular region. Consistent with the
above discussion, if the SDT elects to pursue revisions that accommodate shedding
non-consequential load in transmission planning for single contingency conditions, it
should abandon the stakeholder process approach. The establishment of exceptions
is better suited for regional rules or pursuant to a process outside of the reliability
standards - e.g. via the Rules of Procedure, because such a process is not suited for a
continent-wide reliability standard. Regardless of whether the issue is addressed via
an external process, or left to regional variances, this issue needs to be addressed in a
relatively timely manner because the uncertainty is affecting planning processes.

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment

remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
Southern Company

The use of load dropping should be limited to being only an interim solution while a
project is being completed and nothing else can be done.

Response: An entity can choose to restrict the use of footnote ‘b’ to an interim solution but the SDT believes that there are instances
where a long term use (permanent or near-permanent) of footnote ‘b’ may be appropriate. For example, the amount of Load
involved versus the probability of occurrence might dictate that a long term use is in the best overall interests of the customers. No
change made.
Arizona Public Service
Company

This process is too prescriptive and must be simplified.

Response: Without specific comments, the SDT is unable to respond.
Ameren

To clarify, the Stakeholder Process should not be initiated until the amount of Firm
Demand expected to be interrupted by the TP or PC as mitigation reaches a threshold
of 10 MW. However, at that point, the Stakeholder Process should commence, but
not without incorporating the need to obtain approvals from the stakeholders,
regardless of the amount of load to be interrupted beyond the 10 MW threshold
level, and regardless of the voltage level of the transmission elements involved in the
contingency event(s). As drafted, the Stakeholder Process appears to be silent on
receiving approvals to drop load of less than 25 MW. We believe that this is an
invitation to trouble for the industry. For example, if a TP or PC were to have a
contingency for which the mitigation is to interrupt 15 MW of Firm Demand, all the
stakeholders would be called in just to inform them that their load is subject to

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment
interruption, but their displeasure is not relevant, because the 25 MW interruption
level had not been reached, and approval is not required. Thus, we believe that as
drafted Stakeholder Process needs some additional work before we could support it.

Response: The stakeholder process is required anytime that Load is planned to be interrupted pursuant to footnote ‘b’. Approval by
the applicable regulatory authority or governing body responsible for retail electric service issues is required for planned
interruptions greater than 25 MW. The SDT believes that this level is the appropriate balance to protect the interests of the
customers without being unduly burdensome. No change made.
Southwest Power Pool
Reliability Standards
Development Team

We agree the distinction between consequential and non- consequential is
necessary. We don’t agree that you should plan for non-consequential load
loss/shed. You shouldn’t have to interrupt firm service for n-1 contingency.

Response: The SDT believes that there are instances where use of footnote ‘b’ may be appropriate. For example, the amount of
Load involved versus the probability of occurrence might dictate that a use of footnote ‘b’ is in the best overall interests of the
customers. No change made.
Nova Scotia Power

With regard to the application of Footnote 12 in TPL-001-3, the footnote is only
applied to the contingencies in Table 1 involving loss of a Single Line with a 3 phase
fault (P1) or opening of a line without a fault (P2-1). These are higher probability
events relative to other types of contingencies, and Footnote 12 allows for loss of
load for these events, but does not allow for loss of load for lower probability events
that have the same results, such as P2-2 and P2-3. Take for example a single radial
345kV line feeding a small radial portion of the system, with a line end transformer
and breaker between the transformer and the line. Application of Footnote 12 to
only a P1 event (loss of the line on its own, or loss of the transformer on its own) but
loss of the breaker between the line and the transformer would not be allowed, even
though the result would be the same. Without applying footnote 12 to category P2-2
and P2-3 would mean that Footnote 12 is rendered moot (can never be used).
Similarly, Footnote 12 should be applied to P4 and P5, essentially wherever Footnote
9 is applied, otherwise Footnote 12 can never be applied.

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Question 5 Comment

Response: Industry and the NERC Board of Trustees have approved the use of a Stakeholder Process to address the concerns with
the original footnote ‘b’ and with footnote 12 in TPL-001-2. The Commission’s Order No. 762 found that NERC’s proposed
Transmission Planning Reliability Standard TPL-002-0b, which includes a provision that allows for planned Load shed in a single
Contingency provided that the plan is documented and alternatives are considered in an open and transparent process (“footnote
b”), is vague, unenforceable, and not responsive to the previous Commission directives on this matter. Accordingly, the Commission
remanded NERC’s proposal as unjust, unreasonable, unduly discriminatory or preferential, and not in the public interest. FERC
remanded the standard; not because it contained a Stakeholder Process, but because they wanted the process better defined,
including a blend of quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability
would be maintained. This draft added detail and specificity to the already-approved approach. Based on these facts, the SDT does
not believe it appropriate to move away from the industry and Board of Trustees approved Stakeholder Process approach. No
change made.
The SDT believes that the system should be planned so that a fault on an EHV bus section (or an internal fault on a non-bus-tie EHV
breaker) should not require planned Load loss to resolve system performance issues. No change made.
Northeast Power Coordinating
Council

NPCC reviewed the posted documents, and has no comments for this posting.

END OF REPORT

Consideration of Comments: Project 2010-11 TPL-002 footnote ‘b’ and TPL-001 footnote 12

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions
1. Initial ballot

Anticipated Date
October 2012

2. Recirculation ballot

December 2012

3. BOT approval

February 2013

Draft 7: October 2012

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 7: October 2012

2

Standard TPL-001-2a — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-2a

4.1. Functional Entity

5.

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-001-2, 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-001-2a:










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)

B. Requirements

Draft 7: October 2012

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Standard TPL-001-2a — Transmission System Planning Performance 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 :
•
•
•
•
•
•

Draft 7: October 2012

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.
Controllable Loads and Demand Side Management.

4

Standard TPL-001-2a — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

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5

Standard TPL-001-2a — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

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6

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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
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.

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7

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 7: October 2012

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

8

Standard TPL-001-2a — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

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9

Standard TPL-001-2a — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft7: October 2012

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft7: October 2012

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft7: October 2012

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-2a — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft7: October 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-2a — 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 Contingency 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 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.
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).
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14

Standard TPL-001-2a — 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
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Standard TPL-001-2a — Transmission System Planning Performance Requirements

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

b. Assessment 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 mitigate 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 assure that the applicable regulatory authority or governing body
responsible for retail electric service issues does 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
In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW.
Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does 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.

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Standard TPL-001-2a — 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.

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Standard TPL-001-2a — 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
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Standard TPL-001-2a — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 7: July 2012

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.

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 7: July 2012

20

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 7: July 2012

21

Standard TPL-001-2a — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 7: July 2012

Action

Change Tracking

22

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial postingballot

JulyOctober 2012

2. Recirculation ballot

OctoberDecember
2012

3. BOT approval

Draft 7: JulyOctober 2012

February 2013

1

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 7: JulyOctober 2012

2

Standard TPL-001-2a — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-2a

4.1. Functional Entity

5.

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 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-001-2, 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-001-2a:










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)

B. Requirements

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3

Standard TPL-001-2a — Transmission System Planning Performance 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 :
•
•
•
•
•
•

Draft 7: JulyOctober 2012

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.
Controllable Loads and Demand Side Management.

4

Standard TPL-001-2a — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

Draft 7: JulyOctober 2012

5

Standard TPL-001-2a — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

Draft 7: JulyOctober 2012

6

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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
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.

Draft 7: JulyOctober 2012

7

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 7: JulyOctober 2012

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

8

Standard TPL-001-2a — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

Draft 7: JulyOctober 2012

9

Standard TPL-001-2a — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft7: JulyOctober 2012

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft7: JulyOctober 2012

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft7: JulyOctober 2012

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-2a — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft7: JulyOctober 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-2a — 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 Contingency events.
However, iIn limited circumstances, Non-Consequential Load Loss may be needed throughout the planning horizon to ensure that BES performance
requirements are met. However, Wwhen Non-Consequential Load Loss is utilized within the Near-Term Transmission pPlanning processHorizon to address
BES performance requirements, such interruption is limited to circumstances where the Non-Consequential Load Loss is meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption Non-Consequential Load Loss under footnote 12 exceed ‘x75’ MW.
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).
Draft7: JulyOctober 2012

14

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption NonConsequential 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. .shall document the stakeholder process which shall
The process must include the following:
1. Meetings must be open to all 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 all 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 applicationslocation(s) of the planned Firm Demand interruption NonConsequential Load Loss under footnote 12
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption Non-Consequential 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 Firm Demand interruption NonConsequential Load Loss under footnote 12 which must include the following:
1. Conditions under which Firm Demand interruption 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 Firm Demand Non-Consequential Load Loss MW to be interrupted with:
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Standard TPL-001-2a — Transmission System Planning Performance Requirements

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

a. The estimated number and type of customers affected
b. An aAssessment of the effect of the use of Firm Demand interruption NonConsequential Load Loss under footnote 12 on the health, safety, and welfare of
the community
Estimated frequency of Firm Demand interruption Non-Consequential Load Loss under
footnote 12 based on historical performance
Expected duration of Firm Demand interruption Non-Consequential Load Loss under
footnote 12 based on historical performance
Future plans to mitigate the need for Firm Demand interruption 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 Firm Demand interruption 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 pPlanners and Planning Coordinators

III. Instances for which Regulatory Review Approval of Interruptions of Firm Demand NonConsequential 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 Approval assure that of the use of Firm Demand interruption under
footnote 12 by the applicable regulatory authority or governing body responsible for retail
electric service issues does not object to the use of Non-Consequential Load Loss under footnote
12 is required 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 Firm Demand interruptions 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 Firm Demand interruption Non-Consequential Load Loss under footnote 12
is greater than or equal to 25 MW
Before a Firm Demand interruption under footnote 12 is allowed to be utilized as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues.
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Standard TPL-001-2a — Transmission System Planning Performance Requirements

In no case can the planned Firm Demand interruption Non-Consequential Load Loss under
footnote 12 exceed x75 MW.
Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Non-Consequential Load
Loss under footnote 12 When approval for the use of a footnote 12 Firm Demand interruption is
necessary under items III.1 or III.2 above, the Planning Coordinator or Transmission Planner
must submit the information outlined in items II.1 through II.8 above to the Regional EntityERO
for a determination of whether there are any Adverse Reliability Impacts caused by the request to
utilize footnote 12 for Non-Consequential Load Loss. Within 45 days of receipt of this
information, the Regional Entity must review each proposed use of Firm Demand interruption
under footnote 12 to verify that there are no Adverse Reliability Impacts including any potential
cumulative effect within the Regional Entity’s footprint. If the Regional Entity states that an
Adverse Reliability Impact will result due to the requested Firm Demand interruption, then the
requesting entity may appeal the decision to the ERO. Regional Entity determinations of
Adverse Reliability Impacts are to be evaluated by the Regional Entity through a published
methodology approved by the ERO.

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Standard TPL-001-2a — 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.

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Standard TPL-001-2a — 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
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Standard TPL-001-2a — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 7: July 2012

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.

20

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 7: July 2012

21

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 7: July 2012

22

Standard TPL-001-2a — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 7: July 2012

Action

Change Tracking

23

Implementation Plan for TPL-001-2a
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or approved, that
must be implemented before this standard can be implemented.
TPL-001-2a — Transmission System Planning Performance Requirements
Revision to Sections of Approved Standards and Definitions
There are multiple new definitions in the proposed standard.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result of
Transmission Facilities being removed from service by a Protection System operation designed to isolate the
fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six through
ten or beyond when required to accommodate any known longer lead time projects that may take longer than ten
years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1) Consequential Load
Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected from the System by end-user
equipment.
Planning Assessment: Documented evaluation of future Transmission System performance and Corrective
Action Plans to remedy identified deficiencies.

Compliance with Standards
Standard
TPL-001-2 — Transmission
System Planning Performance
Requirements

Functions That Must Comply With the Associated Requirements
Transmission Planner
Planning Coordinator
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this standard.
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-001-2a, 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-001-2a:
•
•

•
•
•
•
•
•

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)

TPL-001-1, TPL-002-1c, TPL-003-1a, and TPL-004-1 are being retired as they are replaced in their entirety by
TPL-001-2a. TPL-005-0 and TPL-006-0.1 are being retired because their requirements are adequately covered by
the revised TPL-001-2a and NERC’s Rules of Procedure, Section 800. TPL-001-1, TPL-002-1c, TPL-003-1a,
TPL-004-1, TPL-005-0 and TPL-006-0.1 are being retired on midnight of the day immediately prior to the

Effective Date of TPL-001-2a in the particular jurisdictions in which TPL-001-2a is becoming effective.
However, during this 24-month period, all aspects of TPL-001-1 through TPL-006-0.1 shall remain in effect for
compliance monitoring. This 24 month period is to allow entities to develop, perform and/or validate new and/or
modified studies, methodologies, assessments, procedures, etc. necessary to implement and meet the TPL-001-2a
requirements. The specified effective dates are expected to allow sufficient time for proper assessment of the
available options necessary to create a viable Corrective Action Plan that is compliant with the new Standard.
R1. This Requirement is related to maintaining System models and the data needed to do so. This
requirement shall become effective on the first day of the first calendar quarter, 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required, this

October 2012

2

requirement goes into effect on the first day of the first calendar quarter, 12 months after Board of
Trustees adoption.
R7. This Requirement identifies an obligation to determine individual and joint responsibilities for
performing studies needed to do the Planning Assessment. This requirement shall become effective on
the first day of the first calendar quarter, 12 months after applicable regulatory approval. In those
jurisdictions where no regulatory approval is required, this requirement goes into effect on the first day
of the first calendar quarter, 12 months after Board of Trustees adoption.
TPL-001-2a ‘raises the bar’ in several areas where performance requirements have been changed in the new Standard
versus those in existing TPL-001-1, TPL-002-1c, TPL-003-1a and TPL-004-1 because loss of Non-Consequential
Load or interruption of firm transfers is no longer allowed for certain events, whereas the existing Standards were
interpreted by many to allow such actions. As shown in Table 1 of TPL-001-2a, the performance requirements
associated with the following events represent “raising the bar”:
•
•
•
•
•
•
•
•

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)

This “raising the bar” is beyond the control of the Transmission Planner and Planning Coordinator and may have
significant budget, siting, permitting, and construction impacts on many Transmission Owners. To provide
stakeholders with sufficient time to implement changes, a timeframe coincident with the end of the Near-Term
Transmission Planning Horizon has been provided.
Any entity which cannot eliminate the need to trip Non-Consequential Load or curtail Firm Transmission Service
for these performance elements by that date shall submit a mitigation plan to its Regional Entity outlining the
steps it will take to correct the problem. If the entities follow the established ERO procedure for mitigation, it is
the intent of the SDT that no penalties will be assessed.

October 2012

3

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial ballot

October 2012

2. Recirculation ballot

December 2012

3. BOT approval

February 2013

Draft 6: October 2012

Page 1 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1c

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of the
first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Draft 6: October 2012

Page 2 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

Draft 6: October 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

1c

February 2013

Address remand of proposed footnote ‘b’
pursuant to FERC Order RM06-16-009

Revised

Draft 6: October 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if it is: (1) directly served by
the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load. In limited circumstances, Firm Demand may be interrupted throughout the planning horizon to
ensure that BES performance requirements are met. However, when interruption of Firm Demand is utilized within the
Near-Term Transmission Planning Horizon to address BES performance requirements, such interruption is limited to
circumstances where the use of Firm Demand interruption meets the conditions shown in Attachment 1. In no case can
the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 6: October 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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3.
4.
5.
6.
7.
8.

b. Assessment of the effect of the use of Firm Demand interruption under footnote
‘b’ on the health, safety, and welfare of the community
Estimated frequency of Firm Demand interruption under footnote ‘b’ based on historical
performance
Expected duration of Firm Demand interruption under footnote ‘b’ based on historical
performance
Future plans to mitigate the need for Firm Demand interruption under footnote ‘b’
Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote ‘b’
Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent
Transmission Planners and Planning Coordinators

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning
Coordinator must assure that the applicable regulatory authority or governing body responsible
for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW
In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW.
Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand
interruption under footnote ‘b’, 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 ‘b’
for Firm Demand interruption.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
1.2.Initial comment period July 31, 2012 – August 29, 2012.
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Initial posting ballot

JulyOctober 2012

2. Recirculation ballot

OctoberDecember 2012

3. BOT approval

February 2013

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1c

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory approvalauthorities.
In those jurisdictions where no regulatory approval is not required, the effective date will be the
first day of the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise
made effective pursuant to the laws applicable to such ERO governmental authorities. All other
requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect
until the revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

1c

February 2013

Address remand of proposed footnote ‘b’
pursuant to FERC Order RM06-16-009

Revised

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Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process should beis to minimize the likelihood and magnitude of interruption of firm
transfers or Firm Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm Demand will be interrupted if
it is: (1) directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible
Demand or Demand-Side Management Load. Furthermore, iIn limited circumstances, Firm Demand may need to be
interrupted throughout the planning horizon to ensure that BES performance requirements are met. However, Wwhen
interruption of Firm Demand is utilized within the Near-Term Transmission pPlanning process Horizon to address BES
performance requirements, such interruption is limited to circumstances where the use of Firm Demand interruption
meets the conditions shown in Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’
exceed ‘x75’ MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ is reviewed through an open and transparent
stakeholder process. The responsible entity can utilize an existing process or develop a new
process. shall document the stakeholder process which shall The process must include the
following:
1. Meetings must be open to all 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 all 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 applications location(s) of the planned Firm Demand interruption under
footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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
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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

2. Amount of Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
b. An aAssessment of the effect of the use of Firm Demand interruption under
footnote ‘b’ on the health, safety, and welfare of the community
3. Estimated frequency of Firm Demand interruption under footnote ‘b’ based on historical
performance
4. Expected duration of Firm Demand interruption under footnote ‘b’ based on historical
performance
5. Future plans to mitigate the need for Firm Demand interruption under footnote ‘b’
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote ‘b’
7. Alternatives to Firm Demand interruption considered and the rationale for not selecting
those alternatives under footnote ‘b’
8. Assessment of potential overlapping uses of footnote ‘b’ including overlaps with adjacent
Transmission pPlanners and Planning Coordinators

III. Instances for which Regulatory Review Approval of Interruptions of Firm Demand under
Footnote ‘b’ is Required
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning
Coordinator must Approvalassure that of the use of Firm Demand interruption under footnote ‘b’
by the applicable regulatory authority or governing body responsible for retail electric service
issues does not object to the use of Firm Demand interruption under footnote ‘b’ is required 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW
Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an element of
a Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or
Planning Coordinator shall ensure that approval is obtained from the regulatory authority or
governing body responsible for retail electric service issues.
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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

In no case can the planned Firm Demand interruption under footnote ‘b’ exceed x75 MW.
Once assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Firm Demand
interruption under footnote ‘b’When approval for the use of a footnote ‘b’ Firm Demand
interruption is necessary under items III.1 or III.2 above, the Planning Coordinator or
Transmission Planner must submit the information outlined in items II.1 through II.8 above to
the Regional Entity EntityERO for a determination of whether there are any Adverse Reliability
Impacts caused by the request to utilize footnote ‘b’ for Firm Demand interruption. Within 45
days of receipt of this information, the Regional Entity must review each proposed use of Firm
Demand interruption under footnote ‘b’ to verify that there are no Adverse Reliability Impacts
including any potential cumulative effect within the Regional Entity’s footprint. If the Regional
Entity states that an Adverse Reliability Impact will result due to the requested Firm Demand
interruption, then the requesting entity may appeal the decision to the ERO. Regional Entity
determinations of Adverse Reliability Impacts are to be evaluated by the Regional Entity through
a published methodology approved by the ERO.

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

Draft 6: JulyOctober 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

Draft 6: JulyOctober 2012

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

Draft 6: JulyOctober 2012

Page 14 of 14

Implementation Plan for Project 2010-11: TPL Table 1 Order
Standards Involved:
•

TPL-001-1 — System Performance Under Normal (No Contingency) Conditions (Category A)

•

TPL-002-1c — System Performance Following Loss of a Single Bulk Electric System Element
(Category B)

•

TPL-003-1 — System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C)

• TPL-004-1 — System Performance Following Extreme Events Resulting in the Loss of Two
or More Bulk Electric System Elements (Category D)
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.

Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards and no proposed changes to other standards.

Compliance with Standards
The four standards are all applicable to both the Transmission Planner and the Planning Authority.

Effective Dates
The effective date is the date entities are expected to meet the performance identified in these standards.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first calendar
quarter, 60 months after approval by applicable regulatory authorities. In those jurisdictions where
regulatory approval is not required, the effective date will be the first day of the first calendar quarter, 60
months after Board of Trustees adoption or as otherwise made effective pursuant to the laws applicable to
such ERO governmental authorities. All other requirements remain in effect per previous approvals. The
existing Footnote ‘b’ remains in effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect per previous approvals.

Project Revision of TPL-002 footnote ‘b’ and TPL-001
footnote 12
Unofficial Comment Form
Please DO NOT use this form for submitting comments. Please use the electronic form to submit
comments on the Standard. The electronic comment form must be completed by 8 p.m. November
19, 2012. If you have questions please contact Ed Dobrowolski at [email protected] or by
telephone at 609-947-3673.
You can access the project webpage here.
Background Information
This posting is soliciting formal comment.
FERC Order No. 762 issued April 19, 2012 remanded TPL-002-1b as vague, unenforceable, and not
responsive to the previous Commission directives on this matter. The Standards Committee directed
the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of Orders
No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL-001-2
in order to prevent the remand of TPL-001-2.
The SDT adopted a philosophy of minimal changes to the actual footnote itself. This was done to
minimize confusion as to what was changed, for ease of reading and following the footnote, and for
formatting within the actual standards documents. This philosophy resulted in the development of an
attachment to the footnote where the actual changes in response to the Commission Orders are
contained. It should be noted that attachments to standards are part and parcel of the standard itself
and thus are binding to applicable entities.
A data request to collect data to assist the SDT in its work was posted for response in accordance with
Section 1600 of the NERC Rules of Procedure. A spreadsheet summarizing the data request findings
has been included with this posting. Specifically, the data obtained led to the following decisions:
•

Order 762 provided guidance suggesting that a ceiling for footnote ‘b’ use be established.
Therefore, the SDT has set the ceiling for footnote ‘b’ use at 75 MW based on the data
provided. Currently, five entities reported that they utilized footnote ‘b’ for single
Contingencies in their planning process for between 50 and 75 MW of potential Load shed and
no entity reported that it utilized footnote ‘b’ for more than 75 MW. The SDT believes that

with the Stakeholder Process, the involvement of local regulatory and governmental bodies
and by setting a ceiling value for the first time, that it has significantly raised the bar on this
issue. Furthermore, the SDT does not believe that it is appropriate to set a limit that would
automatically eliminate some existing usages and force those entities to construct new
transmission facilities.
•

As shown in the data request findings, the average number of MW used with footnote ‘b’ is
approximately 19 MW. The SDT has set the threshold value for when regulatory review is
required at 25 MW based on this average value. The SDT believes that setting this value as
indicated by the data request findings sets the appropriate balance between the stakeholder
process and the additional step of obtaining regulatory and ERO reviews. And again, the SDT
believes that setting this threshold value so that regulatory and ERO reviews are required for
instances of footnote ‘b’ utilization between 25 and 75 MW significantly raises the bar.

•

The data request showed that the majority of footnote ‘b’ utilizations were at voltage levels
below 300 kV. The SDT believes that this validates the selection of the 300 kV EHV distinction
in Section III of the Attachment where regulatory and ERO reviews are required.

•

The majority of Contingencies cited as causing an entity to utilize footnote ‘b’ were line
outages. This caused the SDT to consider limiting the use of footnote ‘b’ to such types of
Contingencies and eliminating its usage for transformer outages. However, with the number
of instances of transformer outages reported (11), the SDT did not believe such a step was
warranted and has not set up a constraint as to types of Contingencies in association with
footnote ‘b’ utilization.

•

The data obtained did not indicate any way to isolate usage of footnote ‘b’ to the fringes of
the system whether that meant geographical or electrical fringes. The SDT believes that
constraining the use of footnote ‘b’ to the supposed fringes of a system could potentially be
discriminatory and thus invalid. In addition, the introduction of the Stakeholder Process for all
uses of footnote ‘b’ and the regulatory and ERO reviews for the 25 – 75 MW range of use will
allow for a true indication of whether the use of footnote ‘b’ is infringing on societal values
which should be a better arbiter of what constitutes a fringe of the system.

The SDT has made a number of changes to the Attachment based on comments received from the first
posting. Principal among these, was the deletion of the role of the Regional Entity in the review
process and the clarification of the role of the regulatory authorities from approval to review.
The SDT reminds commenters that the Stakeholder Process was previously approved by the NERC
Board of Trustees and that inclusion of this process is not the issue. The issue is clarifying the details of
that process to answer the concerns in Order 762.
There have been no changes to the Implementation Plan originally filed with the standards.

Unofficial Comment Form – Project 2010-11

2

You do not have to answer all questions. Enter All Comments in Simple Text Format. Bullets, numbers,
and special formatting will not be retained.
Insert a “check” mark in the appropriate boxes by double-clicking the gray areas.

Questions
1. Do you agree with the text in the body of the footnote including the maximum capacity threshold?
If you do not support these changes or you agree in general but feel that alternative language would
be more appropriate, please provide specific suggestions in your comments. For the maximum
capacity item, please supply any technical rationale for your comment along with limiting conditions
and any current criteria in use at your entity.
Yes
No
Comments:
2. Do you agree with the description and components of the the Stakeholder Process in Section I of
Attachment 1? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:
3. Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of
Attachment1? If you do not support these changes or you agree in general but feel that alternative
language would be more appropriate, please provide specific suggestions in your comments.
Yes
No
Comments:

Unofficial Comment Form – Project 2010-11

3

4. Do you agree with the text in Section III of Attachment 1? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.
Yes
No
Comments:
5. If you have any other comments on this Standard that you haven’t already mentioned above, please
provide them here:
Comments:

Unofficial Comment Form – Project 2010-11

4

Number Max MW
1
43
1
1
1
2
69
3
12
4
4.3
4
4
5
40
5
5
5
6
30
7
31
8
50
8
8
8
8
8
8
9
20
9
10
40
10
10
11
39
12
63
12
12
12
12

Number of
instances
4

1
1
3

4

1
1
7

2
3

1
24

MW each Planned
Voltage instance upgrade
230
8.4
No
230
8.4
No
230
43
No
115
14
No
230
69
No
100
12
Yes
161
2.5
Yes
161
4.1
Yes
161
4.3
Yes
138
10
Yes
138
25
Yes
230
40
Yes
138
10
Yes
115
30
Yes
115
31
Yes
115
10
No
115
12
Yes
115
9
Yes
115
15
Yes
115
50
No
115
31.8
No
115
17.1
No
115
20
Yes
115
20
Yes
115
40
Yes
230
40
Yes
115
20
No
115
39
Yes
115
40
No
138
40
No
138
3
No
138
20
No
138
15
No

Expected
Estimated In-Service
cost ($M)
Date
Type of Contingency
line
transformer
line
line
line
38.6
2017
line
3 - 12
2015
line
3 - 12
2014
line
3 - 12
2021
line
line
line
line
0.2
2011
line
5.8
2013
line
9.5
2013
line
line
2012
line
line
2013
line
line
line
line
4.7
2014
unspecifed
4.7
2014
unspecifed
33
2012
line
8 - 15
2013
transformer
10 - 20 None
line
100
2012
line
line
line
line
line
line

12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
12
13
13
14
15
16
16
16
16
16
16
16
16
16
16
16
16
16
16

20

2

55
28
75

1
1
19

138
115
138
138
115
138
138
115
115
115
115
115
115
115
115
115
115
115
115
115
115
138
161
138
138
115
138
115
115
230
115
115
115
500
500
115
115

63
40
40
3
62
40
61
4
7
7
6
6
11
11
6
6
20
6
2
20
14
55
28
75.2
3.7
1.2
7.7
15.7
2.1
11.3
5.9
19.9
19.8
3.4
17.5
0.3
5

No
No
No
No
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
No
No
No
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

17.4
15.7
46

13

2013
2014
2014
2012
2012
2014
2014
2012
2012
2010
2012
2010

5.4
5.4
80
12.5
2020
15.9
2013
4.1
2013
1
2013
7.5
2013
8.8
2014
36.4
2014
44.4
2015
20.3
2015
59
2015
62.7
2015
16.4
2018
0.6 TBD
14.5
2014
3.8
2013

line
line
line
line
line
line & transformer
line & transformer
line
line
transformer
transformer
line
line
transformer
line & transformer
line
line
line & transformer
line
transformer
transformer
line
line
line
line
line
line
line
line
line
line
line
line
line
line
line
line

16
16
16
16
16
17
18
18

Total
Instances

Utilize 'b'

8
9

115
115
115
115
500
230
115
115

1
2

8.6
7.1
2.7
12.5
28.3
8
4.1
9.1

78
No
171

Yes
18

Yes
Yes
Yes
Yes
Yes
Yes
Yes
Yes

14.5
0.1
3.76
1.3
12.9
8
14.5
9.75

2013
2012
2012
2011
2013
2014
2019
2012

line
line
line
line
line
line
line
line

20120419-3103 FERC PDF (Unofficial) 04/19/2012

139 FERC ¶ 61,060
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
18 CFR Part 40
[Docket No. RM11-18-000; Order No. 762]
Transmission Planning Reliability Standards
(Issued April 19, 2012)
AGENCY: Federal Energy Regulatory Commission.
ACTION: Final Rule.
SUMMARY: Under section 215 of the Federal Power Act, the Federal Energy
Regulatory Commission remands proposed Transmission Planning (TPL) Reliability
Standard TPL-002-0b, submitted by the North American Electric Reliability Corporation
(NERC), the Commission-certified Electric Reliability Organization. The proposed
Reliability Standard includes a provision that allows for planned load shed in a single
contingency provided that the plan is documented and alternatives are considered and
vetted in an open and transparent process. The Commission finds that this provision is
vague, unenforceable and not responsive to the previous Commission directives on this
matter. Accordingly, the Final Rule remands NERC’s proposal as unjust, unreasonable,
unduly discriminatory or preferential, and not in the public interest.
DATES: This rule will become effective [Insert date 60 days after publication in the
FEDERAL REGISTER].
ADDRESSES: You may submit comments, identified by docket number by any of the
following methods:

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 Agency Web Site: http://www.ferc.gov. Documents created electronically using
word processing software should be filed in native applications or print-to-PDF
format and not in a scanned format.
 Mail/Hand Delivery: Commenters unable to file comments electronically must
mail or hand deliver comments to: Federal Energy Regulatory Commission,
Secretary of the Commission, 888 First Street, NE, Washington, DC 20426.
FOR FURTHER INFORMATION CONTACT:
Eugene Blick (Technical Information)
Office of Electric Reliability
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Telephone: (202) 502-8066
[email protected]
Robert T. Stroh (Legal Information)
Office of the General Counsel
Federal Energy Regulatory Commission
888 First Street, NE
Washington, DC 20426
Telephone: (202) 502-8473
[email protected]
SUPPLEMENTARY INFORMATION:

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139 FERC ¶ 61,060
UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Before Commissioners: Jon Wellinghoff, Chairman;
Philip D. Moeller, John R. Norris,
and Cheryl A. LaFleur.
Transmission Planning Reliability Standards

Docket No. RM11-18-000

Order No. 762
FINAL RULE
(Issued April 19, 2012)
1.

Under section 215(d) of the Federal Power Act,1 the Commission remands

proposed Transmission Planning (TPL) Reliability Standard TPL-002-0b, submitted by
the North American Electric Reliability Corporation (NERC), the Commission-certified
Electric Reliability Organization. The proposed Reliability Standard includes a provision
that allows for planned load shed in a single contingency provided that the plan is
documented and alternatives are considered and vetted in an open and transparent
process.2 The Commission finds that this provision is vague, unenforceable and not
responsive to the previous Commission directives on this matter. Accordingly, the Final

1

16 U.S.C. § 824o(d)(4) (2006).

2

NERC filed a petition seeking approval of Table 1, footnote ‘b’ of four
Reliability Standards: Transmission Planning: TPL-001-1– System Performance Under
Normal (No Contingency) Conditions (Category A), TPL-002-1b – System Performance
Following Loss of a Single Bulk Electric System Element (Category B), TPL-003-1a –
System Performance Following Loss of Two or More Bulk Electric System Elements
(Category C), and TPL-004-1– System Performance Following Extreme Events Resulting
(continued…)

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Rule remands NERC’s proposal as unjust, unreasonable, unduly discriminatory or
preferential, and not in the public interest. We require NERC to utilize its Expedited
Reliability Standards Development Process to develop timely modifications to TPL-0020b, Table 1 footnote ‘b’ in response to our remand.3
I.

Background

2.

Section 215 of the FPA requires a Commission-certified Electric Reliability

Organization (ERO) to develop mandatory and enforceable Reliability Standards, which
are subject to Commission review and approval. Approved Reliability Standards are
enforced by the ERO, subject to Commission oversight, or by the Commission
independently. On March 16, 2007, the Commission issued Order No. 693, approving 83
of the 107 Reliability Standards filed by NERC, including Reliability Standard TPL-0020.4 In addition, pursuant to section 215(d)(5) of the FPA,5 the Commission directed

in the Loss of Two or More Bulk Electric System Elements (Category D). While
footnote ‘b’ appears in all four of the above referenced TPL Reliability Standards, its
relevance and practical applicability is limited to TPL-002-0a.
3

NERC Rules of Procedure, Appendix 3A, Standard Processes Manual at 34
(effective January 31, 2012).
4

Mandatory Reliability Standards for the Bulk-Power System, Order No. 693,
FERC Stats. & Regs. ¶ 31,242, order on reh’g, Order No. 693-A, 120 FERC ¶ 61,053
(2007).
5

16 U.S.C. § 824o(d)(5)(2006).

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NERC to develop modifications to 56 of the 83 approved Reliability Standards, including
footnote ‘b’ of Reliability Standard TPL-002-0.6
A.
3.

Transmission Planning (TPL) Reliability Standards

Currently-effective Reliability Standard TPL-002-0b addresses Bulk-Power System

planning and related transmission system performance for single element contingency
conditions. Requirement R1 of TPL-002-0b requires that each planning authority and
transmission planner “demonstrate through a valid assessment that its portion of the
interconnected transmission system is planned such that the network can be operated to
supply projected customer demands and projected firm transmission services, at all
demand levels over the range of forecast system demands, under the contingency
conditions as defined in Category B of Table I.”7 Table I identifies different categories of
contingencies and allowable system impacts in the planning process. With regard to
system impacts, Table I further provides that a Category B (single) contingency must not
result in cascading outages, loss of demand or curtailed firm transfers, system instability
or exceeded voltage or thermal limits. With regard to loss of demand, current footnote
‘b’ of Table 1 states:
Planned or controlled interruption of electric supply to radial customers or
some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems.
6

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1797.

7

Reliability Standard TPL-002-0a, Requirement R1.

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To prepare for the next contingency, system adjustments are permitted,
including curtailments of contracted Firm (non-recallable reserved) electric
power Transfers.
B.
4.

Order No. 693 Directive

In Order No. 693, the Commission stated that it believes that the transmission

planning Reliability Standard should not allow an entity to plan for the loss of nonconsequential firm load in the event of a single contingency.8 The Commission directed
the ERO to develop certain modifications, including a clarification of Table 1, footnote
‘b.’
5.

In a subsequent clarifying order, the Commission stated that it believed that a

regional difference, or a case-specific exception process that can be technically justified,
to plan for the loss of firm service would be acceptable in limited circumstances.9
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.”10

8

See Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1794.

9

Mandatory Reliability Standards for the Bulk Power System, 131 FERC
¶ 61,231, at P 21 (2010) (June 2010 Order).
10

Id.

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C.
6.

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NERC Petition

On March 31, 2011, NERC filed a petition seeking approval of its proposal to

revise and clarify footnote ‘b’ “in regard to load loss following a single contingency.”11
NERC stated that it did not eliminate the ability of an entity to plan for the loss of nonconsequential load in the event of a single contingency but drafted a footnote that,
according to NERC, “meets the Commission’s directive while simultaneously meeting
the needs of industry and respecting jurisdictional bounds.”12 NERC stated that its
proposed footnote ‘b’ establishes the requirements for the limited circumstances when
and how an entity can plan to interrupt Firm Demand for Category B contingencies.
According to NERC, the provision allows for planned interruption of Firm Demand when
“subject to review in an open and transparent stakeholder process.” 13 NERC’s proposed
footnote ‘b’ states:
An objective of the planning process should be to minimize the likelihood and
magnitude of interruption of firm transfers or Firm Demand following
Contingency events. Curtailment of firm transfers is allowed when achieved
through the appropriate redispatch 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 redispatch does not result in the shedding of any Firm Demand. It is recognized that
Firm Demand will be interrupted if it is: (1) directly served by the Elements
removed from service as a result of the Contingency, or (2) Interruptible Demand
or Demand-Side Management Load. Furthermore, in limited circumstances Firm
Demand may need to be interrupted to address BES performance requirements.
11

NERC Petition at 10.

12

Id.

13

Id.

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When interruption of Firm Demand is utilized within the planning process to
address BES performance requirements, such interruption is limited to
circumstances where the use of Demand interruption are documented, including
alternatives evaluated; and where the Demand interruption is subject to review in
an open and transparent stakeholder process that includes addressing stakeholder
comments.
7.

NERC supplemented the filing on June 7, 2011, in response to a Commission

deficiency letter. NERC explained that “the approach proposed in footnote ‘b’ is equally
efficient because many of the stakeholder processes that will be used in footnote ‘b’
planning decisions are already in place, as implemented by FERC in Order No. 890 and
in state regulatory jurisdictions.”14 NERC also pointed to state public utility commission
processes or processes existing in local jurisdictions that address transmission planning
issues that could serve to provide a case-specific review of the planned interruption of
Firm Demand. According to NERC, such processes would more likely engage the
appropriate local-level decision-makers and policy-makers.
8.

With respect to review and oversight by NERC and the Regional Entities, NERC

submitted that an ERO-specific process would place the ERO in the position of managing
and actively participating in a planning process, which conflicts with its role as the
compliance monitor and enforcement authority. NERC also stated that neither the ERO
nor the Regional Entities will review decisions regarding planned interruptions. Their
role will be limited to reviewing whether the registered entity participated in a
stakeholder process when planning to interrupt Firm Demand. NERC explained that
14

NERC Data Response at 4.

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Regional Entities will have oversight after-the-fact by auditing the entity’s
implementation of footnote ‘b’ to determine if the entity planned on interrupting Firm
Demand and whether the decision by the entity to rely on planned interruption of Firm
Demand was vetted through the stakeholder process and qualified as one of the situations
identified in footnote ‘b.’
9.

Furthermore, NERC stated that an objective of the planning process should be to

minimize the likelihood and magnitude of planned Firm Demand interruptions. NERC
contended that, due to the wide variety of system configurations and regulatory compacts,
it is not feasible for the ERO to develop a one-size-fits-all criterion for limiting the
planned firm load interruptions for Category B events. According to NERC, the
standards drafting team evaluated setting a certain magnitude of planned interruption of
Firm Demand, but there was no analytical data to support a single value, and it would be
viewed as arbitrary.
D.
10.

Notice of Proposed Rulemaking

On October 20, 2011, the Commission issued a Notice of Proposed Rulemaking

(NOPR15) proposing to remand NERC’s proposal to modify footnote ‘b.’ In the NOPR,
the Commission stated that it believed that NERC’s proposal does not meet the directives
in Order No. 693 and the June 2010 Order and does not clarify or define the
circumstances in which an entity can plan to interrupt Firm Demand for a single
15

Transmission Planning Reliability Standards, Notice of Proposed Rulemaking,
76 FR 66229 (Oct. 20, 2011), FERC Stats. & Regs. ¶ 32,683 (2011).

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contingency. The Commission expressed concern that the procedural and substantive
parameters of NERC’s proposed stakeholder process are too undefined to provide
assurances that the process will be effective in determining when it is appropriate to plan
for interrupting Firm Demand, does not contain NERC-defined criteria on circumstances
to determine when an exception for planned interruption of Firm Demand is permissible,
and could result in inconsistent results in implementation. The NOPR stated that the
proposed footnote effectively turns the processes into a reliability standards development
process outside of NERC’s existing procedures. Furthermore, the NOPR stated that
regardless of the process used, the result could lead to inconsistent reliability
requirements within and across reliability regions. While the Commission recognized
that some variation among regions or entities is reasonable, there are no technical or other
criteria to determine whether varied results are arbitrary or based on meaningful
distinctions.
11.

The Commission proposed to provide further guidance on acceptable approaches to

footnote ‘b’ and sought comment on certain options for revising footnote ‘b’, as well as
other potential options to solve the concerns outlined in the NOPR. In response to the
NOPR, comments were filed by seventeen interested parties.16

16

NERC, The Edison Electric Institute (EEI), American Public Power Association
(APPA), National Association of Regulatory Utility Commissioners (NARUC), ITC
Holdings Corp. (ITC), Manitoba Hydro, California Department of Water Resources State
Water Project (California SWP) Hydro One Networks, Inc and the Ontario Independent
Electricity System Operator (Hydro One and IESO), Duke Energy Corporation (Duke),
New York State Public Service Commission (NYPSC), Bonneville Power Administration
(continued…)

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II.

Discussion

12.

For the reasons discussed below, the Commission concludes that NERC’s

proposed TPL-002-0b does not meet the Commission’s Order No. 693 directives, nor is it
an equally effective and efficient alternative. Further, the Commission finds that the
proposal is vague, potentially unenforceable and may lack safeguards to produce
consistent results. On this basis, the Commission remands the proposal to NERC as
unjust, unreasonable, unduly discriminatory or preferential and not in the public interest.
Below, the Commission also provides guidance on acceptable approaches to footnote ‘b.’
13.

The Commission adopts the proposed NOPR finding that the footnote ‘b’ process

lacks adequate parameters. The Reliability Standard requires that, when planning to
interrupt Firm Demand, the Firm Demand interruption must be “subject to review in an
open and transparent stakeholder process that includes addressing stakeholder
comments.”17 Without meaningful substantive parameters governing the stakeholder
process, the enforceability of this obligation by NERC and the Regional Entities would
be limited to a review to ensure only that a stakeholder process occurred. As NERC
explained, Regional Entities’ involvement is limited to after-the-fact oversight by

(BPA), Kansas City Power & Light Company and KCP&L Greater Missouri Operations
Company (KCPL), Midwest Independent System Operator, Inc. (MISO), Public Utility
District No. 1 of Snohomish County, Washington, (Snohomish), Transmission Access
Policy Study Group (TAPS), Powerex Corp. (Powerex), and Florida Reliability
Coordinating Council (FRCC).
17

NERC Petition at 10.

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auditing the entity’s implementation of footnote ‘b’ to determine if the entity planned on
interrupting Firm Demand and whether the decision by the entity to rely on planned
interruption of Firm Demand was vetted through the stakeholder process and qualified as
one of the situations identified in footnote ‘b.’18
14.

Further, the NERC proposal leaves undefined the circumstances in which it is

allowable to plan for Firm Demand to be interrupted in response to a Category B
contingency. The Commission believes that proposed footnote ‘b’ could be used as a
means to override the reliability objective and system performance requirements of the
TPL Reliability Standard without any technical or other criteria specified to determine
when planning to interrupt Firm Demand would be allowable, and without violating any
of the requirements of the TPL Reliability Standard. The TPL Reliability Standard
requires that a planner demonstrate through a valid assessment that the transmission
system is planned and can be operated to supply projected Firm Demand at all demand
levels over a range of forecasted system demands.19 In addition, a planner must consider
all single contingencies under Table 1, Category B and demonstrate system
performance.20 For single contingency events where system performance is not met, a
planner must provide a written summary of its plans to achieve system performance

18

NERC Data Response at 7-9.

19

Reliability Standard TPL-002-0b, Requirement R1.

20

Reliability Standard TPL-002-0b, Requirement R1.3.7.

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including implementation schedules, in service dates of facilities and implementation
lead times.21
15.

However, if system performance is not met for any single contingency event(s)

under NERC’s proposed footnote ‘b,’ a planner could plan to interrupt some portion of
Firm Demand to meet system performance requirements thereby overriding the
performance requirements of the TPL Reliability Standard. For example, if a planner
determines during its annual assessment that for a single bulk-power system transformer
contingency other bulk-power system elements would exceed their thermal ratings, a
planner would have authority under the standard to plan to interrupt Firm Demand to
relieve the exceeded thermal ratings of the bulk-power system elements rather than
planning the system to withstand such a single contingency and avoid shedding firm load
as the performance requirements of the TPL Reliability Standard require. Therefore,
without articulating some bounds on the use of the planned shedding of Firm Demand,
there could be instances of multiple exceptions that could affect the robustness of the
system. Further, contrary to commenters contentions, NERC’s proposal, for example,
has no provision to evaluate this cumulative effect of the individual decisions to shed
firm.22

21

Reliability Standard TPL-002-0b, Requirement R2.

22

BPA Comments at 5 (“The reasons for interrupting Firm Demand would be
documented in studies and demonstrate that there would be no adverse impact to the
BPS”); FRCC Comments at 3 (“Indeed, the transmission planning entity is responsible as
part of the system assessment process under the TPL standards to test remedies to ensure
(continued…)

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16.

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The Commission disagrees with commenters that NERC’s proposed footnote ‘b’

will have no adverse impact on reliable planning of the bulk-power system because
planning to shed Firm Demand is intended to ensure that single contingency events do
not result in adverse impacts and intended to preserve bulk-power system reliability.23
Table 1 of the TPL Reliability Standard identifies the system performance requirements
or “System Limits or Impacts” that a planner must apply during its assessment of
Category B, single contingency events.24 Except in limited circumstances, if a planner
determines that it must plan to interrupt Firm Demand so that it does not violate the Table
1 system performance requirements, a planner should not apply footnote ‘b’ as a
mitigation plan to plan to operate reliably.

The Commission therefore is concerned that

NERC’s proposal provides authority to adjust the TPL Reliability Standard and its system

that they address the problems being caused and do not cause additional problems.”); and
Hydro One Comments at 5 (“Loss of load is under the purview of the regulatory authority
and not NERC, unless it has an adverse impact on the BES which is already taken into
consideration by the TPL standards… In all cases, steps are taken in planning, design and
operations of the system to ensure that Firm Demand shedding would not adversely
impact the BES…”).
23

See, e.g., NERC Comments at 11, TAPS Comments at 10, APPA Comments at

6.
24

Reliability Standard TPL-002-0b, Table 1, Transmission System Standards –
Normal and Emergency Conditions. Table 1 identifies the system performance
requirements or “System Limits or Impacts” which are as follows: “System Stable and
both Thermal and Voltage Limits within Applicable Rating”, “Loss of Demand or
Curtailed Firm Transfers” and “Cascading Outages.”

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performance requirements for each single contingency event that does not meet the
system performance requirements of Table 1.
17.

Further, NERC has not provided technically sound means of determining

situations in which planning to interrupt Firm Demand would be allowable. While
NERC expects that such determinations will be made in a stakeholder process, this
provides no assurance that such a process will use technically sound means of approving
or denying exceptions. The Commission concludes that the multiple stakeholder
processes across the country engaging in such determinations could lead to inconsistent
and arbitrary exceptions including, potentially, allowing entities to plan to interrupt any
amount of Firm Demand in any location and at any voltage level.
18.

While the Commission recognizes that some variation among regions or entities is

reasonable given varying grid topography and other considerations, there are no technical
or other criteria to determine whether varied results are arbitrary or based on meaningful
distinctions. The Commission, thus, concludes that NERC’s proposal lacks safeguards to
ensure against inconsistent results and arbitrary determinations to allow for the planned
interruption of Firm Demand.
19.

A remand gives NERC and industry flexibility to develop an approach that would

address the issues identified by the Commission with the proposed footnote ‘b’
stakeholder process including, as discussed below, definition of the process and criteria
or guidelines for the process.
20.

The Commission believes that, on remand, both NERC and the Commission will

benefit from a more complete record regarding the electric industry’s reliance on planned

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Firm Demand interruptions. In response to the Commission’s request to explain and
quantify the extent to which Firm Demand is planned to be interrupted pursuant to
currently-effective footnote ‘b,’ NERC explained:
NERC and the Regional Entities have not collected statistics or
preformed a survey concerning the prospective implementation of
Footnote b under TPL-002-0a. During the drafting team’s
deliberations concerning TPL-001-2 and TPL-002-0a Footnote b,
including the NERC Technical Conference on Footnote b, the
informal assessments demonstrated that the use of Footnote b would
not be widespread.25
Likewise, several commenters state that the interruption of Firm Demand is rarely
needed, but provide no support for this conclusion.26 For example, EEI asks the
Commission to “recognize” that “…the actions taken as outcomes of the planning review
process, are likely to identify few/isolated circumstances in which these [footnote b]
provisions would be invoked….”27

However, the Commission believes that more

specific information regarding the specific circumstances and frequency with which Firm
Demand is planned to be interrupted will assist both NERC in developing, and the
Commission in reviewing, appropriate revisions to footnote ‘b” on remand. Therefore,
pursuant to section 39.2(d) of the Commission’s regulations,28 we direct NERC to
identify the specific instances of any planned interruptions of Firm Demand under
25

NERC Data Response at 10.

26

See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA Comments.

27

EEI Comments at 2.

28

18 U.S.C. § 39.2(d).

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footnote ‘b’ and how frequently the provision has been used. We direct 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.29 NERC shall submit
this information to the Commission with NERC’s footnote ‘b’ filing that addresses the
concerns in this Final Rule.
21.

We urge NERC to develop in a timely manner an appropriate modification that is

responsive to the Commission’s directives in Order No. 693 and our concerns set forth in
this Final Rule. In that regard, we require NERC to deploy its Expedited Reliability
Standards Development Process to quickly respond to the remand. As the Commission
noted in previous orders, the use of planned or controlled load interruption is a
fundamental reliability issue and, certainty regarding the loss of non-consequential load
for a single contingency event is warranted.30 Thus, using the Expedited Standards
Development Process will more rapidly bring needed certainty to this fundamental
reliability issue.
22.

Below we discuss three concerns: (a) jurisdictional issues, (b) lack of technical

criteria, and (c) the stakeholder process. The Commission also provides guidance on
other acceptable approaches.

29
30

NERC Rules of Procedure, Section 1601 (effective January 31, 2012).

North American Electric Reliability Corp., 130 FERC ¶ 61,200 (2010) (March
2010 Order); North American Electric Reliability Corp., 131 FERC ¶ 61,231 (2010)
(June 2010 Order).

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A.
23.

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Jurisdictional Issues

A number of commenters express concern that the Commission is reaching beyond

its FPA section 215 jurisdiction.31 Commenters assert that the Commission options
exceed its jurisdiction involving acceptable levels and types of service. Commenters
seek assurance that the Commission’s proposal does not infringe on matters reserved to
the States and instead “only prescribe acceptable load shedding as it pertains to wholesale
customers that are in a position to select interruptible or conditional firm transmission
service.”32 NARUC states that “any NERC standard for shedding distribution level load
must be guided by States and that a demonstration that interruption of the load will not
cause instability, uncontrolled separation, or cascading failures on the bulk system is
appropriate for a NERC standard.” 33 NARUC adds that specifications of what retail load
and what levels of retail load can be interrupted is a State determination that is not
reviewable by the Commission. TAPS agrees with NERC that issues pertaining to
whether it is permissible to plan to interrupt firm load involves conflicts among federal,
provincial, state, and local governing bodies.34
24.

The Commission disagrees that it is infringing on State Commissions or

overstepping jurisdictional bounds. In this Final Rule, the Commission remands NERC’s
31

See, e.g., Comments of NERC, NARUC, APPA and TAPS.

32

NYPSC Comments at 5.

33

NARUC Comments at 3-4.

34

TAPS Comments at 9.

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proposed footnote ‘b’ as an inadequate mechanism to address planned curtailment of firm
demand and not responsive to the Commission’s directives in Order No. 693 regarding
this matter. The Commission is not directing that NERC develop a specific solution or
approach on remand. Thus, our remand of the NERC proposed modification to TPL-0020b, Table 1, footnote ‘b’ is fully within the Commission’s authority pursuant to section
215(d)(4) to remand to the ERO for further consideration a modification to a proposed
reliability standard that the Commission disapproves in whole or in part. Moreover,
FPA section 215 gives the Commission jurisdiction over mandatory Reliability Standards
to ensure reliability of the Bulk-Power System.35 Consistent with its statutory authority,
the Commission’s interest and focus in this proceeding is on the planned interruption of
Firm Demand on the Bulk-Power System. The Commission views this matter in the
context of Reliability Standard TPL-002-0b, which requires that in planning the system to
withstand the loss of a single Bulk-Power System element, Bulk-Power System
performance criteria must be met. If it is not met, a corrective action plan is required to
address the Bulk-Power System performance criteria violation. Contingencies studied
pursuant to Reliability Standard TPL-002-0b pertinent to Bulk-Power System facilities
are subject to Commission jurisdiction under FPA section 215. In sum, the performance
of the Bulk-Power System under the TPL-002-0b Reliability Standard is within the
Commission’s jurisdiction.

35

16 U.S.C. § 824o(b)(1).

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B.

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Lack of Technical Criteria
NOPR Proposal

25.

In the NOPR, the Commission proposed to remand NERC’s proposal to modify

Reliability Standard TPL-002-0b, Table 1, footnote ‘b.’ The Commission stated that it
believed that NERC’s proposal does not meet the directives in Order No. 693 and the
June 2010 Order and does not clarify or define the circumstances in which an entity can
plan to interrupt Firm Demand for a single contingency.36 In the NOPR the Commission
expressed concern that NERC’s proposed footnote ‘b’ lacks parameters. Without any
substantive parameters governing the stakeholder process, the enforceability of this
obligation by NERC and the Regional Entities would be limited to a review to ensure
only that a stakeholder process occurred. The Commission noted that NERC appears to
confirm this concern, as NERC explained that Regional Entities’ involvement is limited
to after-the-fact oversight by auditing the entity’s implementation of footnote ‘b’ to
determine if the planned interruption of Firm Demand was vetted through the stakeholder
process.37
26.

Further, in the NOPR the Commission stated that since the proposed footnote ‘b’

contains no constraints, it could allow an entity to plan to interrupt any amount of
planned Firm Demand, in any location or at any voltage level as needed for any single
contingency, provided that it is documented and subjected to a stakeholder process. The
36

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 11.

37

Id. P 12.

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Commission found this result remains contrary to the underlying Reliability Standard and
prior Commission orders.38 The Commission requested comment on this specific
concern of the lack of technical criteria or parameters.
Comments
27.

Some commenters agree with the Commission that there is lack of technical criteria

to determine planned interruption of Firm Demand. For example, California SWP states
that Reliability Standards “should ensure transparent criteria based on technical merits
and not software limitations derived from a desire to mask [locational marginal pricing]
price signals with socialized pricing or on status quo practices.”39 ITC believes that there
is a need for defined parameters that will guide the review of exceptions and that will
prevent planned interruptions from becoming commonplace.40 Manitoba Hydro states
that the characteristics of openness and transparency are indicators of a nondiscriminatory planning process; however, these characteristics do not ensure that certain
reliability criteria of the planned facilities will be met.41
28.

Other commenters disagree with the Commission’s concern that there is a lack of

criteria to determine planned interruption of Firm Demand. NERC states that it does not
believe that an exceptions process that provides defined criteria, with some allowances,
38

Id.

39

California SWP Comments at 4.

40

ITC Comments at 2.

41

Manitoba Hydro Comments at 6.

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could be crafted that would respect pre-existing decision making processes that occur at
state and local jurisdictions. NERC argues that the decision to interrupt local load is
essentially an economic decision – a quality of service issue, not a reliability issue.42
29.

MISO disagrees that additional language would reduce the potential for

inconsistent results and points out that registered entities already have many established
requirements that govern the transmission planning processes.43 MISO believes that if
the Commission determines that criteria are needed, such criteria should be determined
by the stakeholders in the regions though their established stakeholder processes.44 EEI
does not believe that specific criteria should be developed until a better understanding is
obtained regarding the role of service interruptions as a reliability tool.45 EEI believes
that these are appropriate aspects of the NERC proposal that would be readily amenable
to an initial implementation approach, followed by an adjustment period that would
refine the overall process consistent with the Commission’s concerns.
Commission Determination
30.

We believe that openness and transparency do not alone ensure that bulk electric

system performance criteria will be met to ensure system reliability. The Commission is
not persuaded that developing technical criteria is unachievable. As the Commission
42

NERC Comments at 13.

43

MISO Comments at 3.

44

Id. at 5.

45

EEI Comments at 10.

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observed in the NOPR, NERC has thresholds in other reliability contexts, such as
vegetation management pursuant to Reliability Standard FAC-003-1 which applies to all
transmission lines operated at 200 kV and above. Likewise, NERC’s Statement of
Compliance Registry Criteria includes numerous thresholds for determining eligibility for
registration.46
31.

The Commission does not agree with EEI’s recommendation to implement a

stakeholder process that is absent technical criteria but then amend it later. While the
Commission has, in other circumstances, approved a Reliability Standard and, as a
separate action, directed NERC to develop a modification pursuant to section 215(d)(5)
of the FPA, in such proceedings the Commission concluded that the proposed Reliability
Standard was just, reasonable, not unduly discriminatory or preferential and in the public
interest. In the immediate proceeding, however, we cannot make such a finding in light
of the flawed stakeholder process provision.
32.

In response to MISO’s argument that such criteria should be determined by the

stakeholders in the regions though their established stakeholder processes, the
Commission would be amenable to such an approach if, for example, NERC and/or the
Regional Entities developed an exception process that provides flexibility in decisions
based on disparate topology or on other matters since they could utilize their technical

46

See, e.g., NERC Statement of Registry Criteria, section III. The Commission
approved the Statement of Registry Criteria in Order No. 693. See Order No. 693, FERC
Stats. & Regs. ¶ 31,242 at P 95.

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expertise to determine the reliability impact from one region to another. For these
reasons, the Commission concludes that a more defined process is needed with NERCdefined technical criteria to determine planned interruption of Firm Demand. However,
we conclude that the approach of allowing a decentralized process without any
overarching parameters is unacceptable.
33.

With regard to NERC’s comment that the decision to interrupt local load is

essentially an economic decision that is a quality of service issue, not a reliability issue,
the Commission notes that in Order No. 693, we dismissed the argument that it may be
preferable to plan the bulk electric system in such a manner that contemplates the
interruption of some firm load customers in the event of a N-1 contingency, and that such
interruption is based largely on the matter of economics, not reliability.47
C.

Stakeholder Process
NOPR Proposal

34.

In the NOPR, the Commission expressed concern that NERC’s proposed footnote

‘b’ stakeholder process is insufficient to meet Order No. 693 and the June 2010 Order
clarification that a regional difference, or a case-specific exception process that can be
technically justified, to plan for the loss of firm services at the fringes of the systems is
acceptable in limited circumstances.48 The Commission also noted that nothing in the
proposed footnote ‘b’ defines the stakeholder process, other than that it must be an open
47

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1792.

48

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 19.

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and transparent stakeholder process that includes addressing stakeholder comments.49
The Commission noted that any meeting that is open to stakeholders could meet this
criteria.
35.

The Commission further stated that the lack of a defined stakeholder process could

allow a transmission planner to develop a process that provides insufficient opportunity
for stakeholder participation and transparency yet still comply with the standard. The
Commission expressed its belief that nothing in the proposed footnote ‘b’ restricts the
stakeholder process, other than that it must be an open and transparent stakeholder
process that includes addressing stakeholder comments. The Commission requested
comment on whether a stakeholder process is the appropriate vehicle to approve or deny
exceptions to allow entities to plan to interrupt Firm Demand for a single contingency
and if so, whether the proposed footnote ‘b’ would require any stakeholder due process.
Comments
36.

Several commenters believe that NERC’s proposed stakeholder process is the

appropriate venue to approve or deny exceptions to interrupt planned Firm Demand.
NERC and other commenters contend that building on existing stakeholder processes is
appropriate, rather than creating new, duplicative processes. While EEI, APPA, and
TAPS concur with or acknowledge the Commission’s concerns about the inadequacy of
the proposed stakeholder process, they nonetheless urge the Commission to approve

49

Id. P 20.

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NERC’s proposal stating that it reflects the considered expertise that instances of planned
load shed are uncommon and not amenable to a one-size-fits-all approach.50 NERC
believes the introduction of an additional planning process may contribute to further
delays and regulatory confusion. NERC states that “keeping decision-making with those
most impacted by decisions regarding reliability and costs, lack of jurisdictional
authority, and the existence of established open and transparent stakeholder processes –
are the reasons NERC did not create a new stakeholder process.”51
37.

Duke Energy believes that the current Order No. 890-type process involving the

local transmission planning collaborative is the appropriate stakeholder process. Duke
Energy suggests that footnote ‘b’ should be revised to include a local regulatory authority
process as the appropriate stakeholder process to allow entities to plan to interrupt Firm
Demand for a single contingency. According to Duke Energy, in such a process a
transmission planner would submit its plan to interrupt Firm Demand for a single
contingency to its local regulatory authority that has jurisdiction over quality of service to
local load prior to any actual interruption of Firm Demand.
38.

BPA states that the stakeholder process will keep the decision local, where the

parties involved understand the different factors that must be considered in deciding the

50

See, e.g., EEI Comments at 3, TAPS Comments at 5, APPA Comments at 3.

51

NERC Comments at 12.

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proper path forward.52 APPA maintains that these processes impose due process
requirements on the transmission planner, including participation in an open and
transparent stakeholder process that considers stakeholder comments.53
39.

FRCC disagrees with the Commission that enforceability is limited since the

process requires development of a record documenting the decisions and stakeholder
comments and planning authority responses. According to FRCC, the result will provide
NERC and the Commission substantive and procedural grounds to assess whether
sufficient consideration was given to maintaining reliability.54
40.

Some commenters believe that NERC’s proposed stakeholder process is not the

appropriate vehicle to approve or deny exceptions to interrupt planned Firm Demand.
ITC argues that the stakeholder process is inadequately undefined to ensure that planned
Firm Demand interruptions are kept to a minimum. Manitoba Hydro indicates that by
acknowledging an exception for interruptible Firm Demand, NERC appears to recognize
that the right to interrupt is not solely a reliability issue, but also a commercial or legal
issue based on contractual rights.55
41.

While TAPS encourages the Commission to accept NERC’s proposed footnote ‘b,’

it shares the NOPR’s concerns about the adequacy of the open and transparent
52

BPA Comments at 4.

53

APPA Comments at 5.

54

FRCC Comments at 3.

55

Manitoba Hydro Comments at 5.

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stakeholder process and has argued for a decision-making role for transmissiondependent utilities in the Order No. 890 and Order No. 1000 planning processes to ensure
that stakeholder processes do not result in a presentation of a decision followed by the
transmission provider simply “rubber-stamping” the decision.56 If the Commission
determines that these objectives cannot be accomplished without more robust action from
the Commission in this proceeding, TAPS urges the Commission not to remand the
proposed footnote ‘b,’ but instead to accept NERC’s proposal and direct NERC to submit
a further modified footnote ‘b’ to address the parameters of the “open and transparent
stakeholder process that includes addressing stakeholder comments.” 57
Commission Determination
42.

The Commission is not persuaded that the stakeholder process is adequately

defined. The Commission is concerned that the stakeholder process could undermine the
system performance criteria of TPL-002-0b Reliability Standard. As the Commission
stated in Order No. 693, one of the key reliability objectives of the TPL Reliability
Standard is that the system can be operated following the loss of one element and supply
projected firm customer demands and projected firm transmission services at all demand
levels over the range of forecast system demands.58 The Commission finds that the
stakeholder process without appropriate parameters is inconsistent with the reliability
56

TAPS Comments at 5.

57

Id. at 11.

58

Order No. 693, FERC Stats. & Regs. ¶ 31,242 at P 1771.

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objective to supply projected firm customer demands for the loss of one element. While
the Reliability Standard requires that the system is planned so that the system can be
operated following the loss of one element and supply projected firm customer demands,
the proposed stakeholder process could defeat this by allowing a transmission planner to
plan to shed as much load as needed so that the system can be operated to supply
whatever customers remain.
43.

The Commission agrees with TAPS to the extent it observes that the proposal

could allow a transmission planner to utilize a new or existing stakeholder process that
provides insufficient opportunity for a stakeholder to provide meaningful input. We
conclude that the stakeholder process with no criteria to objectively assess whether varied
results are arbitrary or based on meaningful differences is unjust, unreasonable, unduly
discriminatory or preferential, and not in the public interest. Nothing in proposed
footnote ‘b’ defines the stakeholder process, other than it must be an open and transparent
stakeholder process that includes addressing stakeholder comments.
44.

The Commission is not persuaded by FRCC’s comment that enforceability is not

limited by proposed footnote ‘b’ and that development of a record will provide NERC
“substantive and procedural” grounds to assess the outcome of the process. Neither
FRCC nor any other commenter identifies the minimum procedural safeguards to assure
an adequate level of stakeholder participation and consideration of stakeholder comment
in the decision-making process. Moreover, even NERC, which states that it can conduct

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after-the-fact audits, indicates that such audits would not explore substantive adequacy or
the reliability basis for a decision to plan to shed Firm Demand.59 Further, the
Commission is not persuaded by APPA and BPA comments that local stakeholder
participation and due process requirements imposed on the transmission planner are
sufficient. Rather, the Commission believes that if a transmission planner invokes a
process that provides for minimal stakeholder involvement, it could argue that it satisfied
the provision, even if the transmission planner is the ultimate decision maker and simply
‘rubber stamps’ its own proposal to interrupt planned Firm Demand.
D.
45.

Guidance on Acceptable Approaches to Footnote ‘b’

The Commission proposed three options in the NOPR for further guidance on

acceptable approaches to footnote ‘b.’ In addition, the Commission requested comment
on other potential options to solve the concerns outlined in the NOPR.
1.
46.

Existing Protocols to Develop Criteria/Quantitative Limits

In the NOPR, the Commission acknowledged that NERC considered a variety of

limits but observed that NERC’s establishment of some form of criteria for planning to
interrupt Firm Demand could be an acceptable approach for footnote ‘b.’ The
Commission requested comment on whether existing protocols such as the Department of
Energy’s Electric Emergency Incident and Disturbance Report (Form OE-417), which
requires an entity to report a certain amount of uncontrolled loss of firm system loads, or

59

NERC Data Response at 7-9.

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NERC’s Statement of Compliance Registry Criteria could provide guidance to NERC to
devise criteria.
Comments
47.

Commenters were unanimous that the examples of existing protocols would not be

beneficial to devise criteria. NERC and others state that any bright-line megawatt limit
would be inappropriate because the bright-line would be arbitrary.60 Some commenters
do not believe that existing protocols, such as the requirement in Form OE-417 should be
used to determine criteria related to planned loss of Firm Demand.61
48.

BPA, ITC, and Duke Energy comment that setting a quantitative limit would push

transmission planners to plan to meet such a limit for a single contingency in all cases.
Currently, transmission planners start from the premise that no load should be interrupted
in the event of a single contingency. ITC believes that including such an acceptable lost
load criterion as an option could lead to that option being chosen as the “default
solution,” i.e., allowing for a certain amount of acceptable interruption of Firm Demand
without a stakeholder exception review process.62 In the same vein, Duke indicates that a
specific megawatt threshold may prohibit certain interruptions of Firm Demand that
would be acceptable from a quality of service and local consequences perspectives.63
60

NERC Comments at 14.

61

ITC Comments at 5; see also Hydro One and IESO Comments.

62

ITC Comments at 5.

63

Duke Comments at 6.

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Commission Determination
49.

The Commission is persuaded by the commenters that Form OE-417 or the

Registry Criteria are not, by themselves, beneficial to use to devise criteria. The
Commission also agrees that a bright-line criteria by itself does not present a viable
option and would have the potential to constitute an acceptable de facto interruption and
become commonplace to plan to interrupt Firm Demand. For example, if the bright-line
criteria included up to 50 MW of planned interruptible Firm Demand under proposed
footnote ‘b’, then planners may choose to automatically shed up to 50 MW of load as
their first course of action for any single contingency event that would cause a violation
of system performance criteria. This is not an acceptable outcome.
2.
50.

A Blend of Quantitative and Qualitative Thresholds

The Commission also sought comment on whether a blend of quantitative and

qualitative thresholds to be used to interrupt planned Firm Demand would be an
appropriate option for providing criteria that would be generally applicable, but also for
allowing for certain cases that may exceed the criteria. For example, a Reliability
Standard could require a process with a quantitative limitation on how much Firm
Demand could be planned for interruption and the standard could provide an exception
process where a registered entity would submit documents and explanation to the ERO or
a Regional Entity for approval based upon certain considerations.64 The Commission

64

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 18.

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suggested that setting generally applicable criteria for when an applicable entity can plan
to shed Firm Demand, coupled with an exceptions process overseen by NERC and the
Regional Entities, could mean that few exception requests must be processed by NERC
and the Regional Entities.65 The Commission observed in the NOPR that this approach
may satisfy the need for technical criteria while accounting for NERC’s concerns about
the difficulty of developing a one-size-fits-all criterion for limiting planned Firm Demand
interruptions and the appropriateness and feasibility of managing and actively
participating in each planning process.
Comments
51.

California SWP indicates that standards must constrain the use of firm load

shedding as a reliability solution in transmission planning and at the same time, require a
transparent and clearly defined stakeholder process to support any such planned use of
load shedding for single contingency events.66 BPA suggests that, if the Commission
does set a quantitative limit on planned interruption of Firm Demand, a limit based on a
fraction of aggregated normal peak load would be one option that may be more effective
and adaptable to all sizes of utilities.67

65

Id. P 27.

66

California SWP Comments at 2.

67

BPA Comments at 4.

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52.

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Other commenters disagree that a blend is a good option. NARUC indicates that

rather than inventing another stakeholder process by requiring NERC to set specific
quantitative or qualitative requirements for distribution load shedding, NERC should look
to State commissions and existing State curtailment plans to guide load shedding in
contingency planning.68 Duke Energy submits that a blend of quantitative and qualitative
thresholds does not provide enough flexibility to permit the qualitative assessment of the
loads and locations for which transmission planners may interrupt under their exercise of
footnote ‘b’ because a blended threshold may still rely too heavily on a quantitative
threshold for planned interruption of Firm Demand.69 FRCC states it is not feasible to
develop a single quantitative rule that would apply equitably to all stakeholders and
regions.70
53.

EEI believes that adopting a process that would provide greater clarity, reporting,

and refinement would provide the specific information on the extent that the footnote ‘b’
issue presents itself. EEI also agrees with NERC that efforts to create a one-size-fits-all
approach have less value than a process that ensures openness and transparency.

68

NARUC Comments at 3.

69

Duke Energy Comments at 7.

70

FRCC Comments at 7.

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Commission Determination
54.

The Commission believes that setting a quantitative and qualitative threshold in

developing a limited exception for planned interruption of Firm Demand may be a
workable solution. First, qualitative thresholds could be used to overcome the concern
discussed immediately above regarding the quantitative threshold becoming an
acceptable de facto interruption of planned Firm Demand. By utilizing a blend, the
planner must also meet the qualitative threshold which could consist of, for example, the
submittal of documents and explanation to the entity ultimately deciding whether the
planned load shed is acceptable. For example, if 100 MW of planned Firm Demand was
permitted to be interrupted, the planner could not automatically and unilaterally shed up
to 100 MW of planned Firm Demand each time system performance criteria would be
violated. Under the blend concept, the Commission envisions that the planner would
consider up to 100 MW of planned Firm Demand interruption along with other options to
resolve the system performance criteria violation and submit its documentation and
explanation to the entity deciding whether the planned load shed is acceptable. The
concept of a blend of thresholds would prevent an acceptable de facto interruption of
planned Firm Demand and avoid the difficulty of developing a one-size-fits-all criterion
for limiting planned Firm Demand interruptions, but still allow for those limited
circumstances to be reviewed in an exception process where a limited amount of planned
interruption of Firm Demand may be acceptable.
55.

We believe it is appropriate for the Regional Entities, with NERC as the final

authority, to make determinations under a “blended” exception process. First, NERC and

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the Regional Entities provide both objectivity in the decision-making process as well as
the necessary reliability-focused expertise. Second, this should not overly burden NERC
or Regional Entity resources as utilization of the planned load shed exception is – and
would be – rarely utilized.71 Further, we are not persuaded by the assertion that NERC
would be conflicted as the ERO and also inserting itself in the process. NERC’s ERO
role would continue, in coordination with its current responsibilities in implementing
other exceptions such as the Technical Feasibility Exception process under the Critical
Infrastructure Protection Reliability Standards.
56.

The Commission does not agree with BPA’s suggestion of using quantitative

thresholds based on a fraction of aggregated normal peak load. BPA’s suggestion
attempts to address the concerns of commenters that a bright-line threshold must be
established that would be a one-size-fits-all criteria. For example, instead of a megawatt
bright-line threshold for all entities, the ERO could establish a threshold based on a
percentage of aggregated normal peak load. The Commission believes that it would be
difficult to demonstrate that adoption of BPA’s suggestion would be just and reasonable,
not unduly discriminatory or preferential and in the public interest. If criteria were
established that permitted a percentage of aggregated normal peak load as an acceptable
threshold for planned interruption of Firm Demand, even a small percentage could equate

71

See, e.g., FRCC Comments at 4; MISO Comments at 4; BPA Comments.

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to entire towns, cities or regions of load.72 The Commission, therefore, does not support
the planned interruption of Firm Demand based on a fraction of aggregated normal peak
load. The Commission believes that an appropriate mechanism would be based on
impact studies that consider minimizing planned interruption of Firm Demand within,
and adjacent to, communities and small localities.
57.

The Commission offers guidance to NERC to consider the option of a blend of

quantitative and qualitative thresholds. An example of a qualitative threshold could
include identifying geographical or topological “fringes of the system.” While
interruption at the fringes of the system may be expected by some consumers, not all
customers necessarily have that same expectation. For example, we don’t expect that
many water treatment facilities or telecom switching stations normally plan to be
interrupted for single contingency events.73 While the Commission has offered one
example of a qualitative threshold, NERC may explore other qualitative thresholds on
remand. The Commission believes that a blend of quantitative and qualitative thresholds
coupled with an exception process overseen by NERC and the Regional Entities would
be a reasonable option to allow for the limited interruption of planned Firm Demand.

72

For example, the PJM aggregated normal system peak load is approaching
160,000 MW, so a one percent threshold would equate to allowance of planned
interruption for a single contingency of up to 1600 MW of load, which is the size of some
entire towns, cities or regions.
73

While we anticipate that such facilities are prepared for distribution-level
blackouts, we are not aware that they are prepared for a transmission-level blackout.

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Accordingly, the Commission directs the ERO to consider some blend of quantitative and
qualitative thresholds.
3.
58.

Customer or Community Consent

In the NOPR the Commission also requested comment on whether a feasible option

would be to revise footnote ‘b’ to allow for the planned interruption of Firm Demand in
circumstances where the “transmission planner can show that it has customer or
community consent and there is no adverse impact to the Bulk-Power System.”74 The
Commission suggested that this would not require affirmative consent by every
individual retail customer, but would recognize that either group would need to be
adequately defined. The Commission requested comments on who might be able to
represent the customer or community in this option and how customer or community
consent might be demonstrated.75 The Commission also requested comment on how it
would be determined that firm demand shedding with customer consent would not
adversely impact the Bulk-Power System. Additionally, the Commission requested
comment on whether a customer who would otherwise consent to having its planning
authority or transmission planner plan to interrupt Firm Demand pursuant to this option
could instead select interruptible or conditional firm service under the tariff to address
cost concerns.

74

NOPR, FERC Stats. & Regs. ¶ 32,683 at P 28.

75

Id.

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Comments
59.

Several commenters agreed with the Commission that the customer or community

consent should be required. ITC believes the customers or entities should be involved in
a stakeholder process such as a representative group for the affected load or customers
(community representatives or a separate load serving entity where the transmission
provider is not an integrated utility), the public service/utility regulatory commission for
the affected load, the RTO or ISO for the affected area, and any other affected entity.
California SWP also supports notice to and consent of loads (or their wholesale
representatives) that are planned to be interrupted for the loss of a single element.76 In its
comments, California SWP explains that it was “surprised to learn that in lieu of
transmission upgrades, [its transmission planner] relied on interruption of SWP’s large
firm pump loads supposedly receiving the same California Independent System Operator
(CAISO) transmission service as provided to SCE loads. At that time, SWP was not
consulted about the planned curtailment of its firm loads as an alternative to a
transmission upgrade, and thus had no opportunity to correct this error.”77
60.

Other commenters disagree that customer or community consent should be

required. NERC states that it has no relationship with retail customers and, therefore, has
no mechanism to bring retail customers into the conversation. NERC adds that both

76

California SWP Comments at 4.

77

Id. at 2-3.

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wholesale and retail customers are already involved in state processes which provide a
forum for them to be heard.
61.

Hydro One and the IESO submit that customer interests are managed by the

relevant regulatory authority and consent is through regulatory approval. In all cases,
steps are taken in planning, design, and operations of the system to ensure that Firm
Demand shedding would not adversely impact the bulk electric system in addition to the
fact that the customer also has other options such as to select interruptible service.
NYPSC recommends that the Commission only prescribe acceptable load shedding as it
pertains to wholesale customers that are in a position to select interruptible or conditional
firm transmission service under Commission-approved tariffs.
62.

FRCC states that the evaluation of the possible use of interruptible or conditional

firm service instead of planned interruptions of Firm Demand is not warranted.
According to FRCC, the adoption of a Firm Demand interruption alternative would
inherently entail customer benefits from foregone project costs and the non-incurrence of
environmental and other impacts. The customers would also generally enjoy a higher
quality of service than traditional interruptible or conditional firm. Consequently, FRCC
believes that applying any such rate in place of Demand interruption would present
imponderable issues of quantification and application.
63.

BPA does not believe that this proceeding is appropriate to decide issues related to

service choice. BPA argues that the Commission has determined that the rate for
conditional firm service be the same as the firm rate. BPA does not anticipate that the
interruption of Firm Demand would occur on a frequent basis, if at all. Thus, BPA does

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not believe that a customer should pay a different transmission rate under these
circumstances. APPA states that footnote ‘b’ arms wholesale transmission customers and
communities served at retail with information and studies prepared by the transmission
planner, documenting the specific circumstances (i.e., specific Bulk Electric System
Contingency events) under which interruption of Firm Demand may be needed to address
bulk electric system performance requirements.
Commission Determination
64.

We understand NERC’s position that as the entity that addresses Bulk-Power

System reliability, it does not have a mechanism to coordinate with customers. Likewise,
how to define customers and community decisions and engage them in the NERC process
could be challenging.78
65.

At the same time, California SWP provides a compelling example of how a

customer can be adversely affected by planned load shedding for Firm Demand if it was
unaware its load would be interrupted until its load was actually shed. In contrast to
California SWP’s experience, a customer should have notice and understanding that the
transmission planner plans to curtail certain Firm Demand in the event of a single

78

As suggested in the NOPR, customer or community consent would not require
affirmative consent by every individual retail customer, but the process NERC developed
would recognize that either group would need to be adequately defined. We note that,
although NERC comments that it addresses Bulk-Power System reliability, the process
that NERC proposes will impact firm load service to retail customers.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 40 -

contingency indentified in the system modeling under NERC’s Transmission Planning
requirements. NERC should consider these matters on remand.79
Summary
66.

In sum, the Commission remands the proposed footnote ‘b’ and directs NERC to

revise its proposal to address the Commission’s concerns described above, subject to
consideration of the additional guidance provided in this Final Rule.
67.

As stated in the NOPR, NERC will need to support the revision to footnote ‘b.’ If

there is a threshold component to the revised footnote, NERC would need to support the
threshold and show that instability, uncontrolled separation, or cascading failures of the
system will not occur as a result of planning to shed Firm Demand up to the threshold. In
addition, if there is an individual exception option, the applicable entities should be
required to find that there is no adverse impact to the Bulk-Power System from the
exception and that it is considered in wide-area coordination and operations. Further, the
Commission believes that any exception should be subject to further review by the
Regional Entity or NERC.
III.

Information Collection Statement

68.

The Office of Management and Budget (OMB) regulations require that OMB

approve certain reporting and recordkeeping (collections of information) imposed by an

79

We will not consider the tariff-related comments as they are beyond the scope of
this rulemaking.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 41 -

agency.80 The information contained here is also subject to review under section 3507(d)
of the Paperwork Reduction Act of 1995.81
69.

As stated above, the subject of this Final Rule is NERC’s proposed modification to

Table 1, footnote ‘b’ applicable in four TPL Reliability Standards. This Final Rule
remands the footnote ‘b’ modification to NERC. By remanding footnote ‘b’ the
applicable Reliability Standards and any information collection requirements are
unchanged. Therefore, the Commission will submit this Final Rule to OMB for
informational purposes only.
70.

Interested persons may obtain information on the reporting requirements by

contacting the following: Federal Energy Regulatory Commission, 888 First Street,
NE, Washington, DC 20426 [Attention: Ellen Brown, Office of the Executive Director,
e-mail: [email protected], phone: (202) 502-8663, or fax: (202) 273-0873].
IV.

Environmental Analysis

71.

The Commission is required to prepare an Environmental Assessment or an

Environmental Impact Statement for any action that may have a significant adverse effect
on the human environment.82 The Commission has categorically excluded certain actions
from this requirement as not having a significant effect on the human environment.
80

5 CFR § 1320.11.

81

44 U.S.C. § 3507(d).

82

Regulations Implementing the National Environmental Policy Act of 1969,
Order No. 486, 52 FR 47897 (Dec. 17, 1987), FERC Stats. & Regs., Regulations
Preambles 1986-1990 ¶ 30,783 (1987).

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 42 -

Included in the exclusion are rules that are clarifying, corrective, or procedural or that do
not substantially change the effect of the regulations being amended.83 The actions
proposed herein fall within this categorical exclusion in the Commission’s regulations.
V.

Regulatory Flexibility Act

72.

The Regulatory Flexibility Act of 1980 (RFA)84 generally requires a description

and analysis of final rules that will have significant economic impact on a substantial
number of small entities. The RFA mandates consideration of regulatory alternatives that
accomplish the stated objectives of a proposed rule and that minimize any significant
economic impact on a substantial number of small entities. The Small Business
Administration’s (SBA) Office of Size Standards develops the numerical definition of a
small business.85 The SBA has established a size standard for electric utilities, stating
that a firm is small if, including its affiliates, it is primarily engaged in the transmission,
generation and/or distribution of electric energy for sale and its total electric output for
the preceding twelve months did not exceed four million megawatt hours.86 The RFA is
not implicated by this Final Rule because the Commission is remanding footnote ‘b’ and
not proposing any modifications to the existing burden or reporting requirements. With
no changes to the Reliability Standards as approved, the Commission certifies that this
83

18 CFR § 380.4(a)(2)(ii).

84

5 U.S.C. § 601-612.

85

13 CFR § 121.201.

86

Id. n.22.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 43 -

Final Rule will not have a significant economic impact on a substantial number of small
entities.
VI.

Document Availability

73.

In addition to publishing the full text of this document in the Federal Register, the

Commission provides all interested persons an opportunity to view and/or print the
contents of this document via the Internet through FERC's Home Page
(http://www.ferc.gov) and in FERC's Public Reference Room during normal business
hours (8:30 a.m. to 5:00 p.m. Eastern time) at 888 First Street, NE, Room 2A,
Washington DC 20426.
74.

From FERC's Home Page on the Internet, this information is available on eLibrary.

The full text of this document is available on eLibrary in PDF and Microsoft Word
format for viewing, printing, and/or downloading. To access this document in eLibrary,
type the docket number excluding the last three digits of this document in the docket
number field.
75.

User assistance is available for eLibrary and the FERC’s website during normal

business hours from FERC Online Support at (202) 502-6652 (toll free at 1-866-2083676) or email at [email protected], or the Public Reference Room at (202)
502-8371, TTY (202) 502-8659. E-mail the Public Reference Room at
[email protected].
VII.

Effective Date and Congressional Notification

76.

These regulations are effective [insert date 60 days from publication in FEDERAL

REGISTER]. The Commission has determined, with the concurrence of the

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000

- 44 -

Administrator of the Office of Information and Regulatory Affairs of OMB, that this rule
is not a “major rule” as defined in section 351 of the Small Business Regulatory
Enforcement Fairness Act of 1996.
By direction of the Commission. Commissioner Norris is dissenting in part and
concurring in part with a separate statement attached.
(SEAL)

Kimberly D. Bose,
Secretary.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

UNITED STATES OF AMERICA
FEDERAL ENERGY REGULATORY COMMISSION
Transmission Planning Reliability Standards

Docket No. RM11-18-000

(Issued April 19, 2012)

NORRIS, Commissioner, dissenting in part and concurring in part:
The continued implementation and evolution of the mandatory reliability
standards program enacted by Congress in 2005 has been at the forefront of our agenda
since I arrived at the Commission in 2010. As we have grappled with the difficult issues
raised by proposed new or revised standards, and as I have discussed these issues with
regulated industry, state regulators, and the public, I have consistently heard a common
theme: mandatory reliability standards come with costs that consumers ultimately must
bear.
As I have thought about this issue, it has become clear to me that in any discussion
of a new or revised mandatory reliability standard, there is always a tradeoff between the
level of reliability to be achieved by that standard and the costs that the standard will
impose. However, that tradeoff is rarely discussed explicitly in the standards
development process or during the Commission’s review of standards. But, we know
that it is an implicit consideration of entities participating in the standards development
process. I believe it is more appropriate to make those considerations, where they are
relevant, explicit. Therefore, I have advocated for an open dialogue between NERC, the
industry, and the Commission to consider the connection between the mandatory
standards we approve to maintain and improve the reliability of the Bulk Power System
and the costs required to meet those standards.
However, I have perceived some hesitancy in openly addressing costs when
considering reliability matters. This is not surprising, as there are no easy answers to
these tough questions, and regulators and industry charged with assuring reliability will
always be hesitant to be perceived as sacrificing reliability in an effort to save on costs.
While I am not advocating for a cost-benefit threshold for approving reliability standards,
I do not believe that we can ignore the costs of proposed mandatory reliability standards
as we consider whether they are “just, reasonable, not unduly discriminatory or
preferential, and in the public interest”.1 These are issues with real world implications,
1

See 16 U.S.C. 824o(d)(2).

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--2-not just for the reliability and security of our Nation’s electric grid, but for the day-to-day
struggles of local communities to balance the economic realities of many competing
obligations.
I am compelled to raise these issues in this proceeding because I believe that the
Transmission Planning (TPL) Reliability Standard footnote ‘b’ addressed in today’s order
presents a stark example of the tradeoffs that sometimes must be made between
increasing levels of reliability and the costs that come with achieving them. As such, I
hope my comments today will help generate a dialogue on how economics and reliability
fit together when considering mandatory reliability standards.
In today’s order, I agree with the majority’s decision to remand proposed TPL
footnote ‘b’ because it is vague, potentially unenforceable, and lacks adequate safeguards
to determine when planning to shed firm load would be permitted. However, I am
concerned that, in allowing for an exception to the TPL standards requirement that firm
load must be maintained under N-1 scenarios, the order does not sufficiently recognize
that this is both an economic and reliability issue, and must allow for a balancing of the
economic and reliability considerations involved.
There may be cases where planning to avoid shedding firm load in all N-1
scenarios will impose significant costs on customers, with perhaps little added reliability
benefit for those customers. In such instances, I believe that wholesale transmission
customers and local communities with retail load service should be empowered to
consider the economic tradeoffs between incurring costs to avoid shedding firm load
versus planning to shed firm load, as long as that decision does not adversely impact the
reliability of the Bulk Power System. Simply put, if a customer seeks to avoid significant
costs, and can do so without impacting its neighbors, the customer should be making that
decision. Today’s order fails to adequately acknowledge the economic consequences of
having to invest in significant facility upgrades to avoid shedding firm load under certain
N-1 scenarios that may be rare or unlikely and that would have only local impacts.2
2

Transmission Planning Reliability Standards, Order No. 762, 139 FERC ¶
61,060, at P 33 (2012) (“With regard to NERC’s comment that the decision to interrupt
local load is essentially an economic decision that is a quality of service issue, not a
reliability issue, the Commission notes that in Order No. 693, we dismissed the argument
that… such interruption is based largely on the matter of economics, not reliability.”) I
also note that the brief Commission findings in Order No. 693 failed to acknowledge or
sufficiently address this issue, leaving the uncertainty we are still faced with today.
Mandatory Reliability Standards for the Bulk-Power System, Order No. 693, FERC Stats.
& Regs. ¶ 31,242, at P 1791-1794 (2007).

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--3-Accordingly, in my view, the Commission should have directed NERC to revise
footnote ‘b’ to address two broad concerns. First, wholesale transmission customers and
retail load should have the ability to choose whether to shed firm load during an N-1
contingency where that decision will not adversely impact the Bulk Power System.
Second, the decision to shed firm load must be validated to ensure that there is no adverse
impact on the Bulk Power System. Absent this reliability check, the planning of firm
load shedding should not be permitted, because reliability of the Bulk Power System is
paramount. While NERC, the Regional Entity, and/or the local planning authority must
be involved in the reliability check, these entities would not be expected to be involved in
the economic decision.
Additionally, I agree with various comments filed in response to the NOPR that
firm load shedding is and should be used rarely or infrequently. I do not expect that any
new process that NERC may propose to determine whether firm load shedding is
permitted would result in a rush by entities seeking to plan to shed firm load. In other
words, I do not expect this exception to “swallow the rule” under the TPL standards that
firm load may not be planned to be shed for N-1 contingencies.
Finally, the concerns I note above regarding the failure to consider both the
economic and reliability aspects of a decision to plan to shed firm load extend to the
specific guidance provided in the order. The guidance in the order with respect to what
would constitute an allowable exception fails to provide a realistic means for entities to
balance these economic and reliability considerations. Instead, I would have provided
that an entity could submit its plan to shed firm load for a single contingency to its
relevant regulatory authority or governing body prior to any actual interruption.3 The
politically accountable regulatory authority or governing body would have then made the
determination, based upon economics and in the best interests of its customers, as to
whether firm load shedding should be permitted. Those determinations would be subject
to oversight and review by NERC, the Regional Entity, and/or the planning authority to
ensure that they will not adversely impact the Bulk Power System.4

3

See e.g., Duke Energy Corporation Dec. 22, 2011 Comments, Docket No.
RM11-18-000.
4

NERC may propose an alternative to Commission guidance that is equally
efficient and effective at addressing the Commission’s reliability concerns. Order No.
693 at P 31.

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Docket No. RM11-18-000
--4-For these reasons, I respectfully dissent in part and concur in part.

_____________________________
John R. Norris, Commissioner

20120419-3103 FERC PDF (Unofficial) 04/19/2012

Document Content(s)
RM11-18-000a.DOC......................................................1-50

Standards Announcement
Project 2010-11 – TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Initial Ballot open through 8 p.m. Monday, November 19, 2012

Now Available

A single initial ballot is open for revisions to a single footnote that is incorporated into two standards
(TPL-002-1c– System Performance Following Loss of a Single BES Element for footnote ‘b’, and TPL001-2a – Transmission System Planning Performance Requirements for footnote 12 ) through 8 p.m.
Eastern Monday, November 19, 2012.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions

Members of the ballot pools associated with this project may log in and submit their votes for the
footnote in both standards by clicking here.
Next Steps

The drafting team will consider all comments received during the formal comment period and initial
ballot and, if needed, make revisions to the footnote. If the comments do not show the need for
significant revisions, the footnote will proceed to successive ballot.
Background

FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the

footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Wendy Muller,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order

TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12

Formal Comment Period Open: October 5 – November 19, 2012
Upcoming
Initial Ballot: November 9 – November 19, 2012
Now Available
A formal comment period for a revisions to a single footnote that is incorporated into two standards
(TPL-002-1c– System Performance Following Loss of a Single BES Element as footnote ‘b’, and TPL-0012a – Transmission System Planning Performance Requirements as footnote 12) is open through 8 p.m.
Eastern on Monday, November 19, 2012.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC Legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions for Joining Ballot Pool(s)

Registered Ballot Body members must join the ballot pool to be eligible to vote in balloting of a
footnote that is included in standard TPL-002-1c as footnote ’b’, TPL-001-2a as footnote 12. Registered
Ballot Body members may join the ballot pool at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from
using the ballot pool list server.) The ballot pool list server for this ballot pool is: [email protected]
The ballot pool is open through 8 a.m. Eastern on Monday, November 5, 2012.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, November 19, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic

form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the
comment form is posted on the project page.
Next Steps
A single initial ballot for the footnote in both standards will be conducted Friday, November 9, 2012
through 8 p.m. Monday, November 19, 2012.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order

TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12

Formal Comment Period Open: October 5 – November 19, 2012
Upcoming
Initial Ballot: November 9 – November 19, 2012
Now Available
A formal comment period for a revisions to a single footnote that is incorporated into two standards
(TPL-002-1c– System Performance Following Loss of a Single BES Element as footnote ‘b’, and TPL-0012a – Transmission System Planning Performance Requirements as footnote 12) is open through 8 p.m.
Eastern on Monday, November 19, 2012.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC Legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions for Joining Ballot Pool(s)

Registered Ballot Body members must join the ballot pool to be eligible to vote in balloting of a
footnote that is included in standard TPL-002-1c as footnote ’b’, TPL-001-2a as footnote 12. Registered
Ballot Body members may join the ballot pool at the following page: Join Ballot Pool
During the pre-ballot window, members of the ballot pool may communicate with one another by
using the “ballot pool list server.” (Once the balloting begins, ballot pool members are prohibited from
using the ballot pool list server.) The ballot pool list server for this ballot pool is: [email protected]
The ballot pool is open through 8 a.m. Eastern on Monday, November 5, 2012.
Instructions for Commenting
A formal comment period is open through 8 p.m. Eastern on Monday, November 19, 2012. Please use
this electronic form to submit comments. If you experience any difficulties in using the electronic

form, please contact Monica Benson at [email protected]. An off-line, unofficial copy of the
comment form is posted on the project page.
Next Steps
A single initial ballot for the footnote in both standards will be conducted Friday, November 9, 2012
through 8 p.m. Monday, November 19, 2012.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Process Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11 – TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Initial Ballot Results
Now Available

The initial ballot window for the revisions to a single footnote that were incorporated into two
standards (TPL-002-1c– System Performance Following Loss of a Single BES Element as footnote ‘b’,
and TPL-001-2a – Transmission System Planning Performance Requirements as footnote 12) concluded
Monday, November 19, 2012.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results.
Approval
Quorum: 80.45% (updated)
Approval: 56.18%
Next Steps

The drafting team will consider all comments received during the formal comment period and initial
ballot and, if needed, make revisions to the footnote. If the drafting team makes substantive revisions,
the drafting team will submit the revised footnote and consideration of comments received for a
quality review prior to posting for a parallel formal 30-day comment period and successive ballot.
Background

FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the

Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process

The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement | Project 2010-11

2

NERC Standards

 

Newsroom  •  Site Map  •  Contact NERC

  
Advanced Search

 
User Name

Ballot Results

Ballot Name: Project 2010-11 TPL footnote b Initial Ballot October 2012_in

Password

Ballot Period: 11/9/2012 - 11/19/2012
Ballot Type: Initial

Log in

Total # Votes: 288

Register
 

Total Ballot Pool: 358
Quorum: 80.45 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
56.18 %
Vote:
Ballot Results: The standard will proceed to recirculation ballot.

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
102
10
82
25
73
48
0
8
3
7
358

#
Votes

 
1
0.9
1
1
1
1
0
0.5
0.2
0.6
7.2

#
Votes

Fraction
 

40
4
32
5
29
16
0
5
0
6
137

Negative
Fraction

 
0.563
0.4
0.561
0.313
0.592
0.516
0
0.5
0
0.6
4.045

Abstain
No
# Votes Vote

 
31
5
25
11
20
15
0
0
2
0
109

 
0.437
0.5
0.439
0.688
0.408
0.484
0
0
0.2
0
3.156

 
9
1
8
5
12
7
0
0
0
0
42

22
0
17
4
12
10
0
3
1
1
70

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
 
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.

Member
 
Vijay Sankar
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Scott J Kinney

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Ballot
 
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative

Comments
 

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
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1
1
1
1
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1
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1
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
Corporate Risk Solutions, Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
FortisBC
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.

Kevin Smith
Christopher J Scanlon
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Tony Kroskey
John Brockhan
Joseph Turano Jr.
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Joseph Doetzl
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Curtis Klashinsky
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch

Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Affirmative
Affirmative

Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative

Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine

Negative
Affirmative

Michael Moltane

Abstain

Ted Hobson
Walter Kenyon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Mark Ramsey
Michael Jones
Cole C Brodine

Affirmative
Affirmative
Negative
Affirmative
Abstain

Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative

Randy MacDonald

Negative

Bruce Metruck
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne

Negative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative

NERC Standards
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1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Green Cove Springs
City of Homestead
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina

Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Affirmative

Dale Dunckel

Affirmative

Rod Noteboom
Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Rodney A. Wilson
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Gregg R Griffin
Orestes J Garcia
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee
Peter T Yost
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Affirmative
Negative
Negative
Abstain
Negative
Negative

Negative
Negative
Affirmative
Negative
Negative
Negative
Negative

Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative

Abstain
Abstain
Affirmative
Affirmative

Affirmative
Affirmative
Abstain

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4

Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
American Municipal Power
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.

Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
David McDowell
Gary Clear
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kevin Koloini
Ronnie Frizzell
Duane S Dahlquist
Reza Ebrahimian

Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Negative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Affirmative
Negative

Affirmative
Negative

Tim Beyrle
Nicholas Zettel
John Allen

Abstain
Negative

Margaret Powell

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Integrys Energy Group, Inc.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Energy Services, Inc.
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern Indiana Public Service Co.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission

David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Christopher Plante
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Edward F. Groce
Clement Ma

Abstain
Negative
Negative
Negative
Abstain
Abstain
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative

Mike D Kukla
Francis J. Halpin
Shari Heino
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Christy Wicke
Marcus Ellis
Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper
Kenneth Dresner
David Schumann
Preston L Walsh
John J Babik
Brett Holland
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Kim Morphis
Mahmood Z. Safi
Richard K Kinas

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Negative
Negative
Abstain
Negative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Abstain
Affirmative

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Mississippi Electric Power Association
Southern California Edison Company

Roland Thiel
Matt E. Jastram
Annette M Bannon
Tim Kucey
Steven Grega
Michiko Sell
Lynda Kupfer
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Nickesha P Carrol
David J Carlson
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
David Ried
Kelly Cumiskey
Carol Ballantine
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Joel Rogers
Lujuanna Medina

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain

Negative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Negative
Negative
Negative

NERC Standards
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
 

Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
JDRJC Associates
Massachusetts Attorney General
Transmission Strategies, LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

John J. Ciza
Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Negative
Affirmative

Peter H Kinney

Affirmative

David F Lemmons
Roger C Zaklukiewicz
Edward C Stein
Jim Cyrulewski
Frederick R Plett
Bernie M Pasternack
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative

Donald Nelson
Diane J. Barney

Negative

Thomas G. Dvorsky
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Donald G Jones
Steven L. Rueckert
 

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Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA  30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

Copyright © 2012 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=550abcf1-8839-4f8f-be91-301b23616007[11/27/2012 8:20:29 AM]

Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
 

 

 

Individual or group. (61 Responses)
Name (42 Responses)
Organization (42 Responses)
Group Name (19 Responses)
Lead Contact (19 Responses)
Question 1 (48 Responses)
Question 1 Comments (51 Responses)
Question 2 (43 Responses)
Question 2 Comments (51 Responses)
Question 3 (42 Responses)
Question 3 Comments (51 Responses)
Question 4 (46 Responses)
Question 4 Comments (51 Responses)
Question 5 (0 Responses)
Question 5 Comments (51 Responses)

Group
TVA Transmission Reliability Engineering and Controls
Tim Ponseti, VP
Yes
TVA agrees with the general text; however, TVA believes that the 75 MW limit is too low. TVA believes that a
better limit would be 100 MW - which is the amount for load shedding required to be reported under OE-417 under
emergency operational policy. This would allow some future load growth as well as any possible new loads that
may develop quickly in which a utility may not have time to complete necessary projects in a corrective action
plan.
No
TVA recommends that up to 25 MW of planned interruption be allowed without triggering the need for a
stakeholder process. Since the average use given in the survey was 19 MW and there is no evidence of harm to
the BES reliability resulting from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.
No
TVA would like to propose that this Stakeholder process be postponed in the event that a transmission fix for a
load drop issue was already planned within the next 2 or 3 years. Thus the stakeholder process would only occur
for projects that had no fix planned within the next couple of years. TVA is also not sure how to satisfactorily
address “health, safety, and welfare of the community” - TVA would appreciate some guidance on how to properly
address this. TVA believes that item 1.b of Section II could contain CEII information and should have limited
distribution. The appropriate non-disclosure agreements would need to be developed to prevent widespread
publication of the information.
No
TVA believes that the requirements of 25 MW as well as any Bulk contingency over 300-kV is much too
burdensome. TVA believes that only larger load drops (such as 50 MW and above) should require ERO review.
Please see responses to question #2,3, and 4. TVA believes that only load drops of higher magnitudes go thru the
Stakeholder and regulatory review.
Group
Northeast Power Coordinating Council
Guy Zito
No
The 75MW of Firm Demand interruption is retail load that is being dropped. Dropping load in the general sense
should not be endorsed, but it is recogn ized that there are special situations where it cannot be avoided. If a
regulator responsible for retail load is comfortable with greater than 75MW being dropped in a rare situation, there
should not be a requirement to build out of the situation. Provided there is no widespread, adverse effect on the
reliability of the interconnected BES, the effect of a firm demand interruption on customers is under the purview of
the applicable regulatory authority that is responsible for local transmission and retail service over the load to be
curtailed. There is no technical basis for the 75MW figure. It was included as a result of a Section 1600 Data
Request, and is an arbitrary value. There should not be a limit without a technically supportable reliability based
reason.

There are no limits on non-consequential load loss for Single Contingency P2-2 and P2-3 (HV only), multiple

Contingencies P4 and P5 (HV only), and P6 and P7. Footnote 12 allows limited non-consequential load loss for
single contingency P1, Multiple Contingency P3. Non-consequential load loss is not allowed for P2-2 and P2-3
(EHV), and P4 and P5 (EHV). Considering the EHV Facilities, it is not reasonable to accept some non-consequential
load loss for single contingency P1 and P2-3, and then deny it for Multiple Contingency categories P4 and P5 which
are statistically less frequent than the former. Also, the Multiple Contingency P7 (for which there is no limit on
non-consequential load loss) is more frequent than P2-3, P4 and P5. This technical irregularity must be reviewed
and addressed.
Individual
Thad Ness
American Electric Power
Yes
Yes
Yes
Yes

Group
Southwest Power Pool Reliability Standards Development Team
Jonathan Hayes
Yes
Yes
Yes
In this section the reference to Customers should only be Customers of Transmission and not open ended for any
customer. Once it is sold wholesale the TP wouldn’t know where it is being sent to. We would also note that under
some jurisdictions that there is a minimum duration threshold for keeping historical data on some of these events
that are being requested under this section. Need to add language to accommodate these thresholds so as not to
contradict what is being asked for by the regulatory bodies.
No
Section III is superfluous if the regulatory bodies are attending the open stakeholder process. This section should
be removed due to the fact that if there is an issue or question on these events they should be addressed in the
open stakeholder meeting. Not sure why the team decided to add the ERO as an entity to check after the
regulatory body has approved the use. We feel like if there needs to bee coordination between affected entities
that they could participate in the open stakeholder process as well. You could add that they include possible
affected entities to the invite list of the open meeting to discuss these footnote applications under section 1.
Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County
No
We believe the survey significantly underestimated the use of Non-Consequential Load Shedding because the
survey asked about past usage of footnote b under Version 001, not about planned load shedding in TPL version
002 or the proposed footnote 12. TPL version 002 added several new contingencies, and also changed the Non
Consequential Load shedding applicability for several contingencies. We have 4 specific concerns, followed by
several suggested edits: 1) Analyzing the contingencies “P1.4 Loss of a Shunt Device” and “P2.1 Opening of a line
section w/o a fault” are new requirements that will lead to increased use of footnote 12. It is common on fringes of
the interconnected system to have weak sources. Significant utility investment will be redirected to remediate
these fringe performance issues due to the P2.1 and its associated restrictions for firm load shedding and no RAS
or UVLS mitigation. This is a low probability and low impact to the main grid contingency with a high mitigation
cost, given the new mitigation restrictions. 2) Contingencies “P2.2 Bus Section fault” and “P2.3 Internal Breaker
Fault” were previously defined as category “C multiple contingencies” with the restriction that the Firm Load
shedding must be planned/controlled. However Version 002 no longer allows dropping nonconsequential load for
EHV but removes all restrictions for HV load shedding. Since these contingencies result in opening the same
breakers as category P1 contingencies, the use of footnote 12 should be consistent with P1. 3) Contingencies P3.1P3.4 were previously defined as category “C multiple contingencies” with Firm loading shedding allowed. In version

2, these contingencies have been changed from allowing planned load shedding to only allowing NonConsequential load shedding per footnote 12. Although this does not directly impact our utility, the survey results
do not include utilities using “must-run” generation. 4) As demonstrated by multiple questions at the last webinar,
many utilities do not understand the definition of Non-Consequential Loads, and therefore may not have correctly
reported the usage of Non-Consequential Load Shedding. The v2 changes cascade to the unfortunate conclusion
that UVLS and RAS are no longer permitted as cost effective transmission performance mitigation, despite new low
probability contingencies that drive performance problems at the edges of the network. -Proposed changes: A)
Change the maximum amount from 75 MW to 300 MW. Several other standards including CIP have a strong
technical basis for selecting 300 MW as the maximum limit for load shedding programs. B) Footnote 12 on
contingency 2.1 should be replaced with a new footnote 15 that reads “ 15. For this contingency, load which is
served radial from a remaining single source line may be shed as if it were Consequential Load.” This change
would acknowledge that while P2.1 does involve just one element, the likelihood of occurrence is similar to bus
section faults, so the resulting system performance requirements should be similar. C) The first two sentences of
footnote 12 should be deleted. Remove the first sentence because it is general in nature and is a basic tenant of
any load-serving utility. Remove the second sentence because column 7 of Table 1 explicitly states where NonConsequential Load Loss is allowed. D) The third sentence of footnote 12 should have the words “under footnote
12” added. Without this addition, all Non Consequential Load Loss including the allowed loss for P4, P5 and P6
would still be subject to Appendix 1. The revised sentence would read “When Non-Consequential Load Loss is used
under footnote 12 within the Near-Term …”
No
In the first sentence, remove the words “as an element of a Corrective Action Plan.” There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in both the long term and short
term, not as a temporary patch. Requiring the stakeholder process as part of Corrective Action Plan implies that
using footnote 12 cannot be the long term choice. Since a Corrective Action Plan is a “list of actions and an
associated timetable for implementation to remedy a specific problem,” using this term removes the stakeholders
ability to evaluated the costs and benefits and instead requires them to treat this a problem where the only
solution is building new facilities.
No
We suggest removing section 2b “Assessment…health, safety…” for three reasons: 1)All outages have a negative
impact on the community. Outages under footnote 12 do not inherently have more significant impact per MWhr
lost than other outages allowed per Table 1. By requiring additional analysis for a similar societal impact, this
provision discriminates against utilities at the fringes of the system. 2) While reminding planners to consider that
their decisions do have real impacts to real people is a laudable goal, including this provision opens the door to
significant legal liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place to introduce
such a significant requirement. The Adequate Level of Reliability Task Force would be a more appropriate venue
for this idea.
No
1) Similar to our comment on question 2, please remove the words “as an element of a Corrective Action Plan”
from the first sentence. There are cases on the fringes of the system where Non-Consequential Load Loss is the
preferred alternative in both the long term and short term, not as a temporary patch. Since a Corrective Action
Plan is a “list of actions and an associated timetable for implementation to remedy a specific problem,” using this
term removes the stakeholders ability to evaluate the costs and benefits and instead requires them to treat this a
problem where the only solution is building new facilities. 2) For any specific use of footnote b, there could be
several applicable regulatory authorities such as small municipalities or public utility districts. The standard should
clarify whether the planner must show evidence that every authority did not object, or whether the planner only
needs to show that less that 25 MW was not rejected by the regulatory authorities. To accomplish this clarification,
we propose: A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or governing body” to
“regulatory authorities or governing bodies.” B) Add a sentence to bullet 2 to read “If multiple regulatory
authorities or governing bodies are responsible for retail electric service issues, only the portion of NonConsequential Load Loss exceeding 25 MW is subject to section III.”
Public Utility District No.1 of Snohomish County generally disagrees with the October 2012 revision of TPL Table 1
Steady State & Stability Performance Footnotes (Planning Events and Extreme Events). “Footnote b) An objective
of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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 redispatch does not result in the shedding of any Firm Demand. It is recognized that Firm Demand will be
interrupted if it is: (1) directly served by the Elements removed from service as a result of the Contingency, or (2)
Interruptible Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be
interrupted throughout the planning horizon to ensure that BES performance requirements are met. However,
when interruption of Firm Demand is utilized within the Near-Term Transmission Planning Horizon to address BES
performance requirements, such interruption is limited to circumstances where the use of Firm Demand
interruption meets the conditions shown in Attachment 1. In no case can the planned Firm Demand interruption
under footnote ‘b’ exceed 75 MW.” “Footnote 12. An objective of the planning process is to minimize the likelihood

and magnitude of Non-Consequential Load Loss following Contingency events. In limited circumstances, NonConsequential 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 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 NonConsequential Load Loss under footnote 12 exceed ‘75’ MW.” The proposed revisions require that a Transmission
Planner or Planning Coordinator provide assurance that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the interruptions of firm demand under TPL-002
footnote ‘b’ or TPL-001 footnote ‘12’ if the voltage level of the contingency is greater than 300 kV with certain subconditions or if the planned interruption of firm demand under these footnotes is greater than 25 MVA. In addition,
under no case can planned Non-Consequential Load Loss exceed 75 MW. The magnitude and duration of load loss
is a Level of Service (“LOS”) or Customer Service issue that is the jurisdiction of Public Utility Commissions and
Local Electric Utility and Municipality boards. The boards and commissions represent their customers which often
have diverse service and rate expectations that often are a result of local industry requirements, geography,
urban/rural characteristics, and other factors of the particular service territory. Boards and commissions hold
public meetings seeking input on various utility matters that often address services and rates. The rate impacts for
customers are important; often more important than the service levels depending on the particular customer or
customer class. Local boards and commissions are very close to these issues and weigh the input provided through
public testimony to best represent their customer needs over the region they represent and have jurisdiction under
state and local codes to address. The 75 MW Non-Consequential Load Loss threshold and the required NERC
process do not resolve or address a reliability issue. The TPL footnotes address service requirements and should
not be part of a NERC Reliability Standard any more than mandating specific System Average Interruption
Frequency Index ("SAIFI") and System Average Interruption Duration Index ("SAIDI"). The Non-Consequential
Load Loss requirement is an economic driven threshold that is not consistent throughout North America due to
diverse customer needs and expectations. For instance, in some areas it may make economic sense and receive
local approval to fund a $100 million system reinforcement to mitigate 1 in 20 year (5 percent chance of
occurring) 76 MW Non-Consequential Load Loss exposure. However there are many communities that could not
justify or support multi-million facilities to mitigate a 1 in 20 year event that may cause the Non-Consequential
Load Loss of 76 MW of load. Public Utility District No.1 of Snohomish County supports removing the NonConsequential Load Loss thresholds from the TPL Reliability Standards and allow the local boards and commissions
to continue to address Customer Service Level issues as they are closest to the customers’ needs and have
jurisdiction over this issue.
Group
MRO NSRF
WILL SMITH
No
(1) Change the wording at the end of the first sentence from “following Contingency events” to “following
Contingency events and Contingency events during the planned (maintenance) outage of any bulk electric
equipment)”. This would remind Transmission Planners and Planning Coordinators to include the consideration of
planned outages at demand levels for which the outage would be performed. (2) Raise the maximum load
dropping threshold for the footnote from 75 MW to 100 MW. A 100 MW threshold is reasonable because the DOE
uses the intentional dropping of more than 100 MW as one of the thresholds for determininge when enough load is
dropped to justify a formal system event analysis. (3) Add a sentence at the end of the footnote to read, “This
footnote does not apply to any load that is not NERC registered (e.g. load that does not meet the greater than 25
MW NERC registration criterion). (4) If a portion of the non-consequential load loss used to mitigate a contingency
is controllable by a demand side load management system, can it be excluded from the “Firm Demand
interruption” in TPL-002-1c Table I footnote ‘b’ and/or ”Non-Consequential Load Loss” in TPL-001-2a Table 1
footnote 12? Does it have to be curtailed on a pre-contingent basis in order to be excluded from the nonconsequential load total, or can it be excluded even if the curtailment happens through action of the UVLS? Does
this load count towards the 25 MW and 75 MW thresholds? RECOMMENDATION: When describing “interruption of
firm demand” or “non-consequential load loss” in footnote ‘b’ add the language “not counting load shed on a precontingent basis”. This would be added to the last sentence of footnote ‘b’ if it indeed should not be counted
towards the 75 MW threshold. Similar language could be added in Attachment 1 Section III in regards to the 25
MW and 75 MW thresholds and in TPL-001-2a as well. This would explain much more clearly what is counted
towards the two thresholds and decrease confusion. (5) If multiple companies own portions of the nonconsequential load loss a used to mitigate a contingency at a single substation does each company’s load portion
count towards the 25 MW and 75 MW thresholds or does the total load at the substation count? For example,
100% of the load at a substation is set to trip with automatic UVLS. Company A, B, and C own load amounts X, Y,
and Z at the substation. Is the amount of load counted towards the 25 MW and 75 MW thresholds X+Y+Z, or is
each counted separately? RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’ could read
“In no case can the planned Firm Demand interruption from under footnote ‘b’ exceed 75 MW from one entity.”
Similar language could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in
TPL-001-2a as well. This would explain much more clearly what is counted towards the two thresholds and
decrease confusion.

Yes
(1) In Attachment 1 Section I, what is the definition of a “stakeholder”? Which NERC functional entities would be
included (TO, TOP, LSE)? Are the public residential and/or business owners that are affected included in the
definition? Some parties may assume that local government representatives or residential or business owners are
included as stakeholders. We believe it is most appropriate for the Transmission Owners, Transmission Operators,
and Load-Serving Entities to objectively evaluate the risks of load shedding in a local area against the cost impact
of a large transmission project on the rate base. RECOMMENDATION: Define stakeholder to be “affected
Transmission Owners, Transmission Operators, and Load-Serving Entities.” (2) In Attachment 1 Section I item 1,
what does “including applicable regulatory authorities” refer to? Is this the same body that “applicable regulatory
authority or governing body” refers to in Section III? Are these requirements still applicable if the 25 MW threshold
in Section III is not passed? RECOMMENDATION: Attachment 1 Section I Item 1 could read “… including applicable
regulatory authorities or governing bodies responsible for retail electric service issues as described in Section III. A
less vague statement allows the important parties to be included in every instance Attachment 1 is used.
No
Remove Item 2b because it requires the assessment of the footnote application impact on the potential health,
safety, and welfare of the community. These types of assessments should be eliminated because they are not
electric system reliability matters and were not stipulated by FERC.
No
(1) In Attachment 1 Section III, what is the definition of “applicable regulatory authority or governing body”? Is
this the state PSC or PUC? Is it the Regional Reliability Organization (RRO)? Is it the Reliability Coordinator (RC)?
RECOMMENDATION: Depending on the answer to the above question, define “applicable regulatory authority or
governing body” more precisely. The language could read “applicable regulatory authority or governing body
responsible for retail electric service such as the state Public Services Commission or Public Utilities Commission”.
A less vague statement allows the important parties to be included in every instance Attachment 1 is used. (2) In
Attachment 1, if non-consequential load loss is planned at multiple bulk delivery points to mitigate the same
contingency should the total load loss count towards the 25 MW and 75 MW thresholds or should the loads be
counted individually? EXAMPLE: There are two load serving substations (X load at substation B and Y load at
substation C) on a long 115 kV line with 230/115 kV transformation at each end (substation A and substation D).
Automatic under-voltage load shedding is in place at substations B and C, the UVLS relays at each substation
making load trip decisions based on local voltage (i.e. independent operation). If one end of the 115 kV line trips
and 115 kV voltage is below allowable levels at both substations X and Y, then the total load tripped by UVLS will
be X+Y. Does the X+Y value count towards the 25 MW and 75 MW thresholds or are X and Y counted separately?
What if X load is dropped for one contingency and Y load is dropped for a different contingency, is the total load
counted X+Y or each load separately? RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’
could read “In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for any single
contingency.” Similar language could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW
thresholds and in TPL-001-2a as well. This would explain much more clearly what is counted towards the two
thresholds and decrease confusion. (3) If non-consequential load loss is planned at multiple bulk delivery points in
close proximity to mitigate different contingencies should the total load loss count towards the 25 MW and 75 MW
thresholds or should the loads be compared individually? For example, there are two load serving substations (X
load at substation B and Y load at substation C) on a networked 115 kV line with 230/115 kV transformation at
both ends (substation A and substation D). Automatic under-voltage load shedding is in place at substations B and
C that would trip X amount of load if one end of the 115 kV line tripped and 115 kV voltage was below allowable
levels, and would trip Y amount of load if the other end of the 115 kV line tripped and 115 kV voltage was below
allowable levels. Does the X+Y value count towards the 25 MW and 75 MW thresholds or are X and Y counted
separately? In addition to the aforementioned contingencies, if the 115 kV line between substations B and C
opens, both loads X and Y will trip. Now does the X+Y value count towards the 25 MW and 75 MW thresholds? (4)
In Attachment 1, if UVLS relaying is programmed at a sub to trip the load in stages at multiple voltage setpoints,
such that only a fraction of the load is tripped for a given contingency, is the entirety of the load still counted
towards the 25 MW and 75 MW thresholds? EXAMPLE: Substation B has X load that will trip if the BES voltage gets
to 0.92 p.u. and Y that will trip if the BES voltage gets to 0.88 p.u. If only X amount of load is required to mitigate
a single contingency in the near-term TPL assessment, is X load counted towards the 25 MW and 75 MW
thresholds or is X+Y load counted? Is there a difference if the Y load is at a different, nearby substation with both
loads having the aforementioned tripping logic? RECOMMENDATION: In TPL-002-1c, the last sentence in Table I
footnote ‘b’ could read “In no case can the planned Firm Demand interruption under footnote ‘b’ (as demonstrated
in the near-term horizon analysis) exceed 75 MW.” Similar language could be added in Attachment 1 Section III in
regards to the 25 MW and 75 MW thresholds and in TPL-001-2a as well. This would explain much more clearly
what is counted towards the two thresholds and decrease confusion
1. In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption” or “Non-Consequential Load
Loss” be initiated by a manual event such as operator action or does it need to be automatic? RECOMMENDATION:
In TPL-002-1c Table I footnote ‘b’ add a sentence stating “Acceptable methods to enact Firm Demand Interruption
may include manual or automatic processes that can be initiated within a reasonable timeframe”
Group
Arizona Public Service Company

Janet Smith
No
The 75 MW threshold is too low. No technical justification has been given for choosing 75 MW. It should be a
significantly higher value for TPL-002. Currently AZPS does not use non-consequential load dropping to meet any
standard but this option should be preserved. There could be times when alternate to the load dropping would be
building a new transmission line costing hundreds of millions of dollar for a very low probability scenario of high
load conditions. The threshold value should be 100 MW or more.
Yes
No
Item 2b: Reference to health, safety, and welfare is unnecessary. All demand interruption are going to have some
impact on health, safety, and welfare. The impact is subjective and will simply result in unnecessary study reports
by consultants and will act as a road block.
No
The threshold of 25 MW in item 2 of section III is too low. It should be same as the maximum allowed value in foot
note b. In addition, AZPS does not agree that no objection assurance by the Regional Entity should be required.
Once the process has been fully vetted by the stakeholders, including the regulatory authority for retail service,
there is absolutely no need for Regional Entity involvement. There would be no adverse affect of nonconsequential load tripping on the BES. Hence no reason for Regional Entity involvement is needed.
The following comment relates to Table 1. It is not clear why footnote 12 applies only to P2-1. The events P2-2,
P2-3, P4, P5 are much less probable and the footnote 12 should be applicable to all these events. Why is that loss
of non-consequential load is allowed for line tripping without fault but not for a bus fault which is much less likely
and could result into same line trip. Similar arguments apply to other scenarios listed above.
Individual
Travis Metcalfe
Tacoma Power
No
We believe the survey significantly underestimated the use of Non-Consequential Load Shedding because the
survey asked about past usage of footnote b under Version 001, not about planned load shedding in TPL version
002 or the proposed footnote 12. TPL version 002 added several new contingencies, and also changed the Non
Consequential Load shedding applicability for several contingencies. We have 4 specific concerns, followed by
several suggested edits: 1) Analyzing the contingencies “P1.4 Loss of a Shunt Device” and “P2.1 Opening of a line
section w/o a fault” are new requirements that will lead to increased use of footnote 12. It is common on fringes of
the interconnected system to have weak sources. Significant utility investment will be redirected to remediate
these fringe performance issues due to the P2.1 and its associated restrictions for firm load shedding and no RAS
or UVLS mitigation. This is a low probability and low impact to the main grid contingency with a high mitigation
cost, given the new mitigation restrictions. 2) Contingencies “P2.2 Bus Section fault” and “P2.3 Internal Breaker
Fault” were previously defined as category “C multiple contingencies” with the restriction that the Firm Load
shedding must be planned/controlled. However Version 002 no longer allows dropping nonconsequential load for
EHV but removes all restrictions for HV load shedding. Since these contingencies result in opening the same
breakers as category P1 contingencies, the use of footnote 12 should be consistent with P1. 3) Contingencies P3.1P3.4 were previously defined as category “C multiple contingencies” with Firm loading shedding allowed. In version
2, these contingencies have been changed from allowing planned load shedding to only allowing NonConsequential load shedding per footnote 12. Although this does not directly impact our utility, the survey results
do not include utilities using “must-run” generation. 4) As demonstrated by multiple questions at the last webinar,
many utilities do not understand the definition of Non-Consequential Loads, and therefore may not have correctly
reported the usage of Non-Consequential Load Shedding. The v2 changes cascade to the unfortunate conclusion
that UVLS and RAS are no longer permitted as cost effective transmission performance mitigation, despite new low
probability contingencies that drive performance problems at the edges of the network. -Proposed changes: A)
Change the maximum amount from 75 MW to 300 MW. Several other standards including CIP have a strong
technical basis for selecting 300 MW as the maximum limit for load shedding programs. B) Footnote 12 on
contingency 2.1 should be replaced with a new footnote 15 that reads “ 15. For this contingency, load which is
served radial from a remaining single source line may be shed as if it were Consequential Load.” This change
would acknowledge that while P2.1 does involve just one element, the likelihood of occurrence is similar to bus
section faults, so the resulting system performance requirements should be similar. C) The first two sentences of
footnote 12 should be deleted. Remove the first sentence because it is general in nature and is a basic tenant of
any load-serving utility. Remove the second sentence because column 7 of Table 1 explicitly states where NonConsequential Load Loss is allowed. D) The third sentence of footnote 12 should have the words “under footnote
12” added. Without this addition, all Non Consequential Load Loss including the allowed loss for P4, P5 and P6
would still be subject to Appendix 1. The revised sentence would read “When Non-Consequential Load Loss is used
under footnote 12 within the Near-Term …”
No

In the first sentence, remove the words “as an element of a Corrective Action Plan.” There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in both the long term and short
term, not as a temporary patch. Requiring the stakeholder process as part of Corrective Action Plan implies that
using footnote 12 cannot be the long term choice. Since a Corrective Action Plan is a “list of actions and an
associated timetable for implementation to remedy a specific problem,” using this term removes the stakeholders
ability to evaluated the costs and benefits and instead requires them to treat this a problem where the only
solution is building new facilities.
No
We suggest removing section 2b “Assessment…health, safety…” for three reasons: 1)All outages have a negative
impact on the community. Outages under footnote 12 do not inherently have more significant impact per MWhr
lost than other outages allowed per Table 1. By requiring additional analysis for a similar societal impact, this
provision discriminates against utilities at the fringes of the system. 2) While reminding planners to consider that
their decisions do have real impacts to real people is a laudable goal, including this provision opens the door to
significant legal liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place to introduce
such a significant requirement. The Adequate Level of Reliability Task Force would be a more appropriate venue
for this idea.
No
1) Similar to our comment on question 2, please remove the words “as an element of a Corrective Action Plan”
from the first sentence. There are cases on the fringes of the system where Non-Consequential Load Loss is the
preferred alternative in both the long term and short term, not as a temporary patch. Since a Corrective Action
Plan is a “list of actions and an associated timetable for implementation to remedy a specific problem,” using this
term removes the stakeholders ability to evaluate the costs and benefits and instead requires them to treat this a
problem where the only solution is building new facilities. 2) For any specific use of footnote b, there could be
several applicable regulatory authorities such as small municipalities or public utility districts. The standard should
clarify whether the planner must show evidence that every authority did not object, or whether the planner only
needs to show that less that 25 MW was not rejected by the regulatory authorities. To accomplish this clarification,
we propose: A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or governing body” to
“regulatory authorities or governing bodies.” B) Add a sentence to bullet 2 to read “If multiple regulatory
authorities or governing bodies are responsible for retail electric service issues, only the portion of NonConsequential Load Loss exceeding 25 MW is subject to section III.”
Individual
Steven R. Wallace
Seminole Electric Cooperative, Inc.
Yes
No
#1. It is unclear what factors must be met in order to be an affected stakeholder under the Stakeholder Process in
Attachment 1? This process appears to be devoid of any objective factors that can assist an entity in determining
whether a party is a stakeholder or not. NERC should define what an “affected stakeholder” is or list factors to
assist industry in making such a determination. #2. In Standard TPL-002-1c, Attachment 1, Section I.
“Stakeholder Process,” there was a section added at the end of this subsection that is three lines in length. This
section states that a stakeholder process does not need to be repeated unless there has been a “material change.”
It is clear from the latest webinar presentation on this Project that this language is not “clear and unambiguous”.
NERC does not present any metrics, whether qualitative or quantitative, to guide industry as to when a material
change occurs to an application of footnote ‘b.’ Without any metrics to guide industry, it is bewildering that NERC
reasons that entities will consistently interpret what a material change constitutes. Therefore, SECI believes that
this provision is in conflict with the NERC Rules of Procedure and FERC Order 762. #3. In Standard TPL-002-1c,
Attachment 1, Section I. “Stakeholder Process,” the requirement that the process “shall be documented” was
deleted from the first paragraph. It does not appear to be reasonable that a process that is not written, nor known
to any stakeholder, meets the common understanding of “open and transparent.” Seminole believes that the
requirement that the process be documented and that documents be available to potential affected parties be
reinstated into the Standard.
Yes
Yes

Individual
Nazra Gladu
Manitoba Hydro

No
Given that it is deemed that a stakeholder procress is required, there is no rationale for a maximum level. The
stakeholders are in the best position to judge the appropriate level of allowable curtailment.
No
A stakeholder process should not be required in jurisdictions where a legislation already authorizes interruptions,
as consent of stakeholders cannot override legislation.
No
The word ‘assure’ should be ‘ensure’ in the opening paragraph of III. Instances for which Regulatory Review of
Non-Consequential Load Loss under Footnote 12 is Required.
(1) Effective Date section 5: The language used in the revision that was made is fine, however, where the
language has been placed in the section is confusing. The language has been added to the end of the sentence
that starts ‘in those jurisdictions where regulatory approval is not required’ and lumped those two concepts
together. In our mind, there should be 3 separate concepts 1) where regulatory approval required 2) where
regulatory approval not required and 3) as may otherwise be approved by applicable laws. (2) Corresponding
changes do not appear to have been made, TPL 1 and TPL 2 are not consistent in terms of the language used in
the Effective Date section or the Attachment 1 (the sections to which changes were made since last circulation).
Individual
James Tucker
Deseret Generation & Transmission
No
The limitation of Non-Consequential load loss to the 25 MW-75 MW level with a hard limit at 75 MW is arbitrary
and give no deference to the cost of the cure. In the West the high cost of a fix may not be in the public interest.
The 75 MW hard high limit should be replaced with a soft 75 MW limit but allowing higher levels if the governing
body or regulatory authority approves it.
Yes
Yes
Yes

Individual
Melissa Kurtz
USACE
Individual
Chris Pink
Tri-State Generation & Transmission Association
No
No
NERC Functional Model definitions for Planning Authorities and Transmission Planners do not include the types of
activities being proposed in “Attachment 1.” How is it appropriate to mandate to functional entities functions that
are outside those defined in the NERC functional model?
No
In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that the end-use customer makes
available to its Load-Serving Entity via contract or agreement for curtailment.” The process described in
Attachment 1 creates an agreement between stakeholders (aka “end-use customers”) and their transmission
providers. Thus, if the process described in Attachment 1 is followed, the “Firm Demand” referenced would be
reclassified as “Interruptible Demand.” In essence, “Footnote b” does not allow the interruption of Firm Demand. It
merely requires that if interruption of Demand is required, it can only be Interruptible Demand. If this was the
intention of FERC, NERC, and the Drafting Team, why didn’t the drafting team just state “Interruption of Firm
Demand is not allowed”?
No
How would section III of “Attachment 1” be applied to entities that only deliver wholesale electric service and no
retail electric service?
It is not clear how transmission projects with long lead times (such as T-lines) would be handled by “Footnote b”.
Is it the drafting team’s intent to make it acceptable for a TP to plan for shedding Firm Demand in the Near Term

Planning Horizon without meeting the conditions shown in “Attachment 1” when a mitigating project is planned
that cannot be constructed in the Near Term Planning Horizon?
Individual
Andrew Z. Pusztai
American Transmission Company
No
ATC recommends the following alternative language for both Footnote ‘b’ (Table 1 in TPL-002-1c [page 6]) and
Footnote ‘12’ (Table 1 in TPL-001-2a [page 14]: (1) Change the wording at the end of the first sentence from
“following Contingency events” to “following Contingency events for the prior condition of all equipment in service
or during the planned (maintenance) outage of any bulk electric system equipment”. This would remind
Transmission Planners and Planning Coordinators to include the consideration of planned outages at demand levels
for which the outage would be performed. (2) In the last sentence of the footnote, raise the maximum load
dropping threshold for the footnote from 75 MW to 100 MW. A 100 MW threshold is reasonable because the DOE
uses the intentional dropping of more than 100 MW as one of the thresholds for determining when enough load is
dropped to justify a formal system event analysis. (3) Add a sentence at the end of the footnote to read, “This
footnote does not apply to any load that is not NERC registered (e.g. load that does not meet the greater than 25
MW NERC registration criterion).
Yes
No
ATC recommends the following change in Section II of Attachment 1 applicable to both standards TPL-002-1c
[page 8] and TLP-001-2a [page16]: Remove Item 2b altogether because it requires the assessment of the
footnote application impact on the potential health, safety, and welfare of the community. These types of
assessments should not be required in the Standards because they are not electric system reliability matters and
were not stipulated within the FERC Order762.
Yes

Individual
John Collins
Platte River Power Authority
No
We do not support a maximum threshold. 1) It is not appropriate to enforce a one size fits all maximum value that
might unnecessarily over-burden some communities. 2) The public process proposed in this standard provides
significant transparency from the transmission utilities and opportunity for community input to decisions that will
impact both the community's reliability and rates. 3) Leave the maximum capacity threshold decisions to local
regulatory commissions and Boards of Directors.
Yes
Although these descriptive steps for a public process seem out of place in a reliability standard, Section 1 is in line
with the planning principles of FERC Order 890.
Yes
No
See answer to Question 1.
Individual
Don Jones
Texas Reliability Entity
Yes
Attachment 1, section I (Stakeholder Process) should be clarified to specify which ‘responsible entity’ needs to
utilize or develop a transparent stakeholder process. For example, if a contingency event in Entity A’s system
causes Entity B to have to shed non-consequential firm load to meet the BES performance requirements, which
Entity is responsible for ensuring the required review? TRE proposes adding the following sentence to the first
paragraph to assign responsibility for this type of scenario: “The Planning Coordinator or Transmission Planner
accountable for the contingency event will be responsible for implementing the stakeholder process and regulatory
review.”
Yes

In Section II, part 1b, TRE suggests replacing ‘applicable rating’ with ‘steady state performance requirments’, to
account for all the BES performance requirements (in particular, steady-state and post-contingency voltages) for
which the footnote may be utilized.
Yes
1. TRE requests clarification whether the 25 MW limit of Non-consequential Load Loss (Section III (2)) applies to a
single contingency event for a specific Transmission Planner’s region or to the entire Planning Coordinator area.
For example, if a single contingency requires multiple Transmisson Planners to shed load, is each Transmission
Planner allowed to drop up to 25 MW of load before requiring regulatory review? Or did the SDT intend to require
the Transmission Planners/Planning Coordinator to submit the plan for regulatory review if the total load shed for
the single contingency equals or exceeds 25 MW? 2. TRE feels that the requirement in Section III that the Planning
Coordinator or Transmission Planner must submit information to the ERO for a determination of whether there are
“any Adverse Reliability Impacts” is overly burdensome to industry, assuming that this refers to the new definition
of “Adverse Reliability Impact” (limited to Instability and Cascading). It is extremely unlikely that any such impacts
will result from application of this footnote, and any that might occur will be identified in the stakeholder process.
If the ERO determination step is retained, then a timeline should be included for completion of the ERO
determination process.
Individual
Kirit Shah
Ameren
No
It appears that a least common denominator approach was used to develop the upper limit of 75 MW. Only 1 out
of 18 respondents would drop 75 MW of load, and only two respondents would drop 61-70 MW of load. Our review
of the data request responses concludes that only 22% of the respondents that presently utilize footnote “b” would
drop more than 50 MW, and only 33% of the respondents that use footnote “b” would drop more than 40 MW. The
proposed 75 MW limit is too high and is not supported by the responses to the data request. An upper limit of 40
MW is more appropriate, based on the data responses.
No
It is our opinion that that the stakeholder process should be conducted at least once every five years if nonconsequential load is planned to be dropped as part of the Corrective Action Plan to meet single contingency
events. If conditions have not materially changed since the last review, this information should still be
communicated to the stakeholders.
Yes
We believe that item 1b of Section II would contain critical electric infrastructure information (CEII) and should
have limited distribution. The appropriate non-disclosure agreements would need to be developed to prevent
widespread publication of the material.
No
The responses to the data request indicate that 33% of the respondents that use footnote “b” would drop 20 MW
or less for single contingency events. Based on the data, we believe that the threshold for reporting should be 20
MW instead of 25 MW. As noted above in the response to item 1, we also believe that an upper limit of 40 MW
should be established, again based on the responses to the data request. We find this proposed stakeholder
process unique because we are inviting retail regulatory authorities to become involved in the compliance process
for a handful of utilities now, but potentially for more in the future. We are unaware of any other standards where
a state governmental agency is needed to grant permission for utilities to utilize certain aspects of the standard.
We believe that this proposed process would potentially set a bad precedent, is not good policy for either the
regulators or the transmission planners, and does not belong in a NERC standard.
It might be helpful to probe further with the respondents who have no planned upgrades identified to address the
dropping of non-consequential load to see what relevant system upgrades might entail, and the estimated costs
associated with such upgrades, to address such situations.
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
No
As an initial matter, ERCOT does not believe the planning process should allow for nonconsequential load shedding
under single contingency conditions. Accordingly, ERCOT takes no position on the proposed maximum load
shedding amount. Even though the NERC BoT approved the Stakeholder Process, ERCOT does not believe that the
Stakeholder Process should be included as an Attachment to a footnote to a reliability standard. Also, there is an
inconsistency in the terminology used in the footnotes relative to the load shed – firm demand and nonconsequential load are both used. Non-consequential load is the correct term and the language should be
consistent. Although it is ERCOT’s position that non-consequential load should not be allowed to be shed under
single contingency conditions from a planning perspective, if the SDT elects to retain a vehicle for such exceptions,

it should establish objective, reliability based criteria that lend themselves to inclusion in a reliability standard. This
is consistent with the general approach for reliability standards, which prescribe the "what", not the "how". If the
exceptions are based on objective criteria that are known upfront, and those criteria reflect appropriate reliability
based technical justifications, then the risk of unwarranted exceptions to the general prohibition due to misuse of
the exception process is mitigated. Furthermore, the exception process should be external to the NERC Reliability
Standards (e.g. in the Rules of Procedure), which should merely reference authorized exceptions granted pursuant
to that process. With respect to the stakeholder process, in no case should a reliability standard mandate a
stakeholder process in any respect, procedural or substantive. In ISO/RTO regions, stakeholder processes fall
within ISO/RTO governance matters. These issues are beyond the purview of NERC Reliability Standards. In other
regions, although the relevant functional entities do not have stakeholder processes analogous to ISOs/RTOs, any
relevant processes are similarly beyond the scope of the reliability standards. Accordingly, the SDT should
eliminate all revisions related to the establishment of a stakeholder process. As discussed in response to question
5, FERC is not requiring this approach, but rather has only provided guidance with respect to ways to possibly
bring the prior proposal in line with applicable regulatory approval standards for reliability standards. Additionally,
as a general matter, substantive reliability standards requirements should not be imbedded within a footnote to a
requirement. In this case, not only is there a substantive requirement imbedded in the footnote, there is also a
substantial attachment (which must become part of the enforceable standard requirements}… and, to make it
worse, the attachment is an attachment to the footnote, rather than an attachment to and referred to by a
reliability standard requirement.
No
Please see ERCOT's response to Question 1 – stakeholder processes are not appropriate for NERC standards.
No
Please see ERCOT's response to question 1-the NERC Reliability Standards should not contain requirements related
to stakeholder processes, whether they are procedural or substantive. If an exception process is retained, it should
be outside of the NERC Reliability Standards (e.g. in the Rules of Procedure). To the extent the proposed standard
inappropriately retains the stakeholder related aspects, ERCOT also provides the following comments on Section
II-the ERCOT comments are in parentheses for easy reference and distinction relative to the proposed
requirements. II. Information for Inclusion in Item #3 of the Stakeholder Process The responsible entity shall
document the planned use of Firm Demand interruption under footnote 'b' which must include the following:
(ERCOT COMMENT: This is all that is needed for this. The documentation would be relative to the objective criteria
developed for this purpose.) 1. Conditions under which Firm Demand interruption under footnote 'b' 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 (ERCOT COMMENT: "1" is
not necessary if objective criteria are developed as benchmarks for the exception process. In that case, exceptions
would only be allowed if the objective criteria were met, regardless of the underlying assumptions related to
conditions and contingencies.) 2. Amount of Firm Demand MW to be interrupted with: a. The estimated number
and type of customers affected b. Assessment of the effect of the use of Firm Demand interruption under footnote
'b' on the health, safety, and welfare of the community (ERCOT COMMENT: The considerations reflected in a and b
are inappropriate for a reliability standard. Appropriate considerations for reliability standards are related to the
reliability performance of the system. The considerations in a and b are more akin to quality of service issues
better suited for regional policy discussions. It is not within the purview of the SDT to address those matters.) 3.
Estimated frequency of Firm Demand interruption under footnote 'b' based on historical Performance (ERCOT
COMMENT: Historical performance is irrelevant. If the SDT is going to retain revisions that accommodate nonconsequential load shedding, then the only relevant metrics are the objective criteria that set the benchmarks for
such exceptions.) 4. Expected duration of Firm Demand interruption under footnote 'b' based on historical
performance (ERCOT COMMENT: See ERCOT response to "3" above.) 5. Future plans to mitigate the need for Firm
Demand interruption under footnote 'b' (ERCOT COMMENT: This is redundant to the requirement in the reliability
standards that requires a plan to resolve any violations identified in the planning process. Furthermore, if load
shedding is allowed, this requirement doesn't make sense. Presumably the idea behind allowing these exceptions
is to obviate the prospective need for other alternatives. If that is not the case, then there is no need to allow the
exceptions, because the transmission upgrades to mitigate the need for load shedding can be established in the
planning horizon.) 6. Verification that TPL Reliability Standards performance requirements will be met following the
application of footnote 'b' (ERCOT COMMENT: The basis for the load shedding exception is to provide a means to
meet the TPL performance requirements in the context of a planning assessment. Accordingly, this is redundant to
the planning assessments, the point of which is to identify and resolve performance issues.) 7. Alternatives to Firm
Demand interruption considered and the rationale for not selecting those alternatives under footnote 'b' (ERCOT
COMMENT: Load shedding exceptions should be based on objective criteria and be reviewed pursuant to a process
external to the NERC reliability standards. Alternative discussions could be part of that external process.) 8.
Assessment of potential overlapping uses of footnote 'b' including overlaps with adjacent Transmission Planners
and Planning Coordinators (ERCOT COMMENT: It is not clear what this means. Each functional entity performs
assessments relative to its own system. This appears to introduce a vague regional transmission planning
requirement with no structure or rules for such assessments.)
No
If non-consequential load shedding is allowed for single contingency conditions, as discussed above, it should be

based on objective critieria. As such, there is no need for the proposed stakeholder process, including the Section
Ill instances requiring regulatory review. Furthermore, establishing approval roles in planning processes for entities
other than the relevant functional entities conflicts with the appropriate roles, and appropriate separation of those
roles, of the relevant entities (i.e. the planning authority and the state regulatory body and NERC RE). Typically a
functional entity performs the functional activity, and others relevant to the proposed process in the standard
perform compliance and regulatory oversight of the functional performance. This is a practical concern, and also
potentially raises conflicts between governing authorities that create the separation of roles, where, typically, the
relevant authorities establish a functional entity as the planning entity, and NERC and its REs and state regulators
(as relevant – e.g. in ERCOT) are charged with compliance and regulatory oversight. As with the other stakeholder
process sections, that section should be eliminated.
The SDT is not required to utilize the stakeholder approach by Order 762 or any other relevant FERC orders. FERC
merely provided guidance as to how the rejected proposal could be improved. However, if the SDT elects to pursue
an exception process, such exceptions should be based on objective criteria, and the process should be external to
the NERC Reliability Standards (e.g. in the Rules of Procedure). In Order 693, FERC directed NERC to clarify
footnote (b) to prohibit shedding firm load except for consequential load loss (Order 693 at PP 1773, 1794 and
1797}. In a related compliance order, FERC reaffirmed its position. (130 FERC 61,200 (March 18, 2010) at PP 8-10
(Compliance Order)) In a subsequent order, FERC clarified that its Order 693 directive did not preclude
consideration of specific comments related to planning the system based on load shedding at the “fringes" of a
system. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification Order)) FERC held that regional variances for
case-specific circumstances or a case-specific exception process to plan for the loss of firm service “at the fringes
of various systems" would be acceptable. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification Order))
However, FERC also stated that it viewed the basis for such exceptions as economic, not reliability, with the
justification being that it was not economic to invest in the bulk electric system to serve all non-consequential load
customers under some single contingency conditions. (Order 693 at P 1792) FERC made clear that any such
regional differences or case specific exception processes cannot reflect the lowest common denominator, and, they
must be technically justified, and such justification must be strong. (Clarification Order at P 21, See also Order 693
at P 1794) This is consistent with FERC's position that this is a matter of "fundamental issue of transmission
service". (Order 693 at P 1793) In recognizing that meeting firm demand under single contingency conditions is
fundamental to transmission service, FERC noted that NERC's definition of firm transmission service is the "highest
quality (priority) service offered to customers ... that anticipates no planned interruption." (Order 693 at P 1793)
Against this background, NERC filed revisions to footnote b that allowed transmission plans to shed nonconsequential load under single contingency conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, {139 FERC 11 61,060 (April 19, 2012)) FERC rejected the approach
proposed by NERC and provided guidance on acceptable approaches to footnote b. However, FERC did not endorse
or mandate any particular approach. Rather, it merely urged "NERC to develop in a timely manner an appropriate
modification that is responsive to the Commission's directives in Order No. 693 and our concerns set forth in this
Final Rule." (Order 762 at P21) FERC stated that in order for any such proposal to have merit, it must be
technically justified and must not reflect the lowest common denominator. As discussed, the proposed stakeholder
approach is not appropriate for NERC Reliability Standards. The SDT should abandon that approach and consider
simple revisions to footnote b that reference a case by case exception process based on objective criteria that is
external to the NERC Reliability Standards (e.g. Rules of Procedure). Alternatively, it should develop revisions to
the continent-wide standards that clarify that non-consequential load shedding is not generally permitted for single
contingency conditions, but, consistent with FERC's orders, exceptions could be established pursuant to regional
rules based on the need/appropriateness in a particular region. Consistent with the above discussion, if the SDT
elects to pursue revisions that accommodate shedding non-consequential load in transmission planning for single
contingency conditions, it should abandon the stakeholder process approach. The establishment of exceptions is
better suited for regional rules or pursuant to a process outside of the reliability standards - e.g. via the Rules of
Procedure, because such a process is not suited for a continent-wide reliability standard. Regardless of whether
the issue is addressed via an external process, or left to regional variances, this issue needs to be addressed in a
relatively timely manner because the uncertainty is affecting planning processes.
Individual
David Kiguel
Hydro One Networks Inc.
No
We disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard.
Provided there is no widespread, adverse effect on the reliability of the interconnected bulk electric system, the
effect on customers of a firm demand interruption is the responsibility of the applicable regulatory authority or its
delegated agencies responsible for local transmission and retail service over the load to be curtailed. If it is
decided to proceed with the 75 MW or any other value, we propose replacing the sentence, in the footnote and in
attachment one, section III that reads: “In no case can the planned Non-Consequential Load Loss under footnote
12 exceed 75 MW.” with “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 under footnote 12 for a nonUS Registered Entity should be determined by the applicable Regulatory Authority or Governmental Authority or its
delegated agency in that is responsible for retail electric service issues in that jurisdiction.”

No
The process presented in Section I is overly prescriptive. If a section that prescribes the principles of a stakeholder
process is required, then for non-US entities this section should simply require that the process must be approved
by the applicable Regulatory Authority or Governmental Authority or its delegated agency that is responsible for
local transmission and retail service for the load to be curtailed in that jurisdiction.
No
The process presented in Section II is overly prescriptive. If a section that prescribes the information requirements
for a stakeholder process is required, then for non-US entities this section should simply require that the process
information requirements must be in accordance with the requirements of the applicable Regulatory Authority or
Governmental Authority or its delegated agency that is responsible for local transmission and retail service in that
jurisdiction.
No
The process presented in Section III is overly prescriptive and duplicates information not necessary for its intended
purpose. As stated in Q1, we disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a
continent-wide standard, and propose alternate language in our response to Q1. If this section is required to
address a review of the use of footnote 12 to ensure that there are no wide-spread adverse reliability impacts on
the bulk power system, then it should be limited to the information required for that purpose. Provided there is
local support for the use of Non-Consequential Load Loss under footnote 12, only information items 6 and 8 from
section II are relevant for this assessment—the remainder are not required for this section and should be deleted.
Items 1 and 2 complicate this section and are unneccesary. They should be replaced by a phrase such as “for
those planning events where the use of footnote 12 is referenced.” We disagree with the need to submit this
information to the ERO for a determination of whether there are any Adverse Reliability impacts caused by the use
of Non-Consequential Load Loss. This will introduce a new type of review at the ERO that will create uneccesary
delays and burden, and is inconsistent with (and not required for) all of the other performance requirements in the
TPL standards. Submitting the analysis to the adjacent Planning Coordinators and Tranmission Planners, and any
functional entity that requests it, as called for in requirement R8 of TPL-001-2 should be sufficient.
(1) We’d like to reiterate our support for allowing load interruption for a single contingency with sufficient
review/oversight and under acceptable conditions, including no adverse impact on the reliability of the bulk electric
system. The reliability aspects (BES performance requirements) should be reviewed for acceptability by the
adjacent Planning Coordinators and Transmission Planners. However, issues pertaining to economics or
externalities which may not be directly reliability-related are always available for review and debate by the
stakeholders via the regulatory processes and subject to approval by the regulatory authority of each jurisdiction
(particularly those in Canada and Mexico). (2) Furthermore, we request that Table 1 of TPL-001-2a (previous TPL001-2 approved by the NERC BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the
application of footnote 12 that is allowed for the P1 events. If a load is allowed to be interrupted for a single EHV
transmission line contingency (Category P1), it should be allowed to interrupt the same load if the primary breaker
fails (the event becomes category P4) and the fault is cleared by other breakers. Similarly, if the same breaker has
an internal fault or there is a fault on the same bus section (Category P2) or there is a failure of a relay (Category
P5), which results in the loss of the same EHV transmission line, it should be allowed to interrupt the same load.
Events in P2, P4, and P5 can involve more elements and can be more onerouse and stressful to the system than
the P1 events, and if use of footnote 12 is permitted in the less stressful P1 events, it must also be permitted in
P2, P4 and P5 events. This issue has been raised by many entities in previous occasions and we believe the STD
has not provided a convincing response. (3) We suggest that NERC Standards and their requirements should focus
on what is the anticipated outcome rather than how to achieve them. Accordingly, we believe that the focus of foot
note ‘b’, and footnote 12 should be that interruption of load must not have a widespread, adverse impact on the
reliability of the interconnected BES. A continent-wide reliability standard should not concern itself with the
reliability of supply or supply continuity for local load, as that is the responsibility of the applicable regulatory
authority or its agencies responsible for local transmission and retail service over the load to be curtailed. If NERC
and/or FERC believe that MW threshold needs to be addressed within NERC Standard for US registered entities
then the standard must clearly state that the requirement is for US registered entities only.
Group
Seattle City Light
paul haase
Individual
Martyn Turner
LCRA Transmission Service Corporation
No
No
No

No
LCRA TSC disagrees with the October 2012 revision of TPL Table 1 Steady State & Stability Performance Footnotes
(TPL-002-1c, footnote ‘b’ and TPL-001-2a footnote 12). The proposed stakeholder process required to be
conducted during each Planning Assessment is overly burdensome. Further, it is not clear from the proposed
process that a key concern expressed by the Commission with respect to use of Firm Demand load shedding is
addressed - Notice to Firm Demand Customers. In addition, the proposed stakeholder process introduces several
questions that need to be further clarified. For example: 1) Who defines the processes and procedures to be used?
2) Who is/are the decision maker(s)? 3) Who determines if the processes and procedures were followed? 4) Who
carries out the administrative tasks (such as notice, securing meeting space,….)? 5) Who can participate? Does
someone need to demonstrate a material interest in order to participate? 6) What are the means of participation
(accepted forms of communication, timelines…)? 7) What are the criteria for decision-making? 8) What is the
process for dispute resolution? How would does an Attachment become part of a NERC Standard? Should
Attachment 1 be a requirement? In addition, support is needed for the bright-line 25 MW level. Lastly, the
statement, “Before a Firm Demand interruption under footnote ‘b’ is allowed to be utilized as an element of a
Corrective Action Plan in Year One of the Planning Assessment,” implies that Firm Demand interruption may be
used for years two through five of the Planning Assessment without the stakeholder process.
Group
Duke Energy
Greg Rowland
No
Regarding the maximum capacity item, we believe that 75 MW is much too low. While Duke Energy has not
historically used the footnote, setting the upper limit at 75 MW raises a concern. An upper limit of 75 MW severely
limits the ability of a Transmission Planner to use the footnote. The 75 MW limit appears to be the maximum
reported in the survey. The survey is a snapshot in time and to assume that there never have been nor never will
be situations where the correct decision of a Transmission Planner and its stakeholders would be to exceed the 75
MW limit is illogical. The 75 MW limit is likely to create a situation where a Transmission Planner is forced to
convert a network line to radial in order to remain in compliance with the standard, to the detriment of reliability
to customers. The key to understanding use of the footnote is realizing that, in most cases, using the footnote is
extremely unlikely to result in customer outages, because the probablility of the initiating contingency occurring
under conditions requiring additional load shed is very low. A more reasonable upper limit would be the 300 MW
limit that is established as the threshold for DOE Disturbance Reporting. It is also important to remember that no
matter what upper limit is established, Non-consequential Load Loss of 25 MW or greater cannot be included in
Year One of the Planning Assessment if the applicable regulatory authority or governing body responsible for retail
electric service issues objects.
Yes
Yes
Yes

Individual
Joe Tarantino
Sacramento Municipal Utility District
No
There is no reliability benefit with an establish MW threshold. Implementing any threshold is descriptive and the
standard should depict an outcome not the means of the outcome.

1) The decision of necessary infrastructure addition versus a determination of load shed in lieu of costly
transmission should be determined at the Public Utility Commission or Local Board of Directors not through a laod
level limitation. 2) There are no impacts to the BES for load shedding actions where it is determined that it is
confined to a set boundaryand demonstrate to not lead to cascading, uncrontrolled separation or blackout. 3)
Where a concern that a stakeholder process be "gamed" to allow the unscrupulous entity to claim notification of
affected stakeholders was followed should not dictate a continent-wide standard direction for other stakeholders.
Individual

Patricia Robertson
BC Hydro and Power Authority

BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c – System Performance Following
Loss of a Single BES Element (footnote b) and TPL-001-2a – Transmission System Planning Performance
Requirements (footnote 12). BC Hydro votes YES in support of this ballot and wishes to provide the following two
comments: 1.At this time BC Hydro has concerns about the level of stakeholder consultation that might be
required as a result of the implementation of this standard and will bring this concern to the attention of our
regulator if necessary. 2.At this time BC Hydro has concerns about the instances for which regulatory review of
non-consequential load loss under footnote 12 is required and will discuss those with our regulator if necessary.
Group
Bonneville Power Administration
Chris Higgins
Yes
Yes
No
BPA does not support including information under Section II.2.b, an assessment of the use of Non-Consequential
Load Loss on the health, safety, and welfare of the community. It would be nearly impossible for a planner to
predict this in a future case since it is hard to predict what loads will actually materialize in the future. In addition,
this information does not support reliability of the BES since reliability of the transmission system is assessed by
meeting required technical performance for certain contingencies and under certain conditions.
No
For use of Non-Consequential Load Loss in Year One of the Planning Assessment, BPA believes that assurance
received from the applicable regulatory authority or governing body responsible for retail electric service issues is
adequate and submission to the ERO for a determination of adverse impact is unnecessary. The local utility and
regulators are better positioned to determine adverse impacts on an individual system, whereas the ERO would
have to develop a process and criteria for assessing adverse impacts.
Individual
Terry Harbour
MidAmerican Energy Company
No
MidAmerican supports NSRF comments with one change. The proposed NSRF addition of “consideration of planned
outages at demand levels for which the outage would be performed” to the text of footnote “b” after “following
Contingency events” should not be added. If the addition is made, a reasonable time frame clarification is
necessary and should be added such as “greater than 6 months”. The proposed change would then read
“consideration of planned outages greater than 6 months or longer at demand levels for which the outage would
be performed”.
Yes
However, see the NSRF comments
No
See the NSRF comments
No
Item III of Attachment I should be deleted completely. Non ERO regulatory review is not necessary. Applicable
regulatory authority or governing bodies responsible for retail electric service issues are stakeholders which may
participate in the stakeholder process. Further, there are concerns compliance may not be possible because item
III makes non-NERC applicable regulatory authorities or governing bodies responsible for retail electric service
issues part of a NERC mandatory compliance without consequence to the said non-NERC governing bodies. NonNERC entities are not constrained by NERC mandatory laws and penalties and aren't compelled to perform actions
to meet NERC compliance. This opens a risk to any NERC regulated entities governed by such regulatory or
governing bodies that do not or may not feel compelled to have a process for the NERC regulatory review specified
in item III of attachment I.
See the NSRF comments

Individual
Andrew Gallo
City of Austin dba Austin Energy
Individual
Jason Marshall
New England States Committee on Electricity (NESCOE)
No
The New England States Committee on Electricity (NESCOE) appreciates the opportunity to comment on NERC’s
proposed revisions to Transmission Planning (TPL) Reliability Standards relating to permissible applications of
planned load interruption. NESCOE is New England’s Regional State Committee and is governed by a board
appointed by the six New England Governors. These comments reflect the collective view of the six New England
states. The issue of planned, limited load interruption rests at the central intersection of cost and reliability. It
illustrates the fundamental balance that Commissioner Norris details in Order No. 762: the tradeoffs between
“increasing levels of reliability and the costs that come along with achieving them.” Transmission Planning
Reliability Standards, Order No. 762, 139 FERC ¶ 61,060 (April 19, 2012) (Norris, Comm’r. concurring in part and
dissenting in part) at 2. NESCOE agrees with Commissioner Norris that, as a general matter, this balancing should
translate to a more explicit consideration of costs in the NERC standard development process. Id. at 1. The
language in footnote “b”—and corresponding footnote 12 of TPL-001-2—implicitly recognizes cost considerations in
transmission planning by tolerating limited load shedding under defined circumstances. NESCOE offers below
comments and suggestions in response to the SDT’s questions. These responses reflect NESCOE’s interest in
planning for a robust bulk electric system while taking into account the magnitude of risk that a solution is
intended to address and the costs associated with competing solutions. NESCOE appreciates the work of the SDT
in attempting to respond to the Commission’s directives and the time constraints under which the SDT was
required to make changes to footnote “b.” However, NESCOE is concerned that establishing a bright-line maximum
capacity threshold that is an absolute ceiling is overly prescriptive and unnecessary to meet the Commission’s
directives. In Order 762, the Commission rejected the contention that regional stakeholder processes should
unilaterally determine the appropriate criteria to apply in planning to interrupt firm load. Order 762 at P 32.
However, provided that technical parameters are in place, the Commission stated that it would be “amenable” to
regional stakeholders establishing such criteria if, for example, NERC or the applicable Regional Entity “developed
an exception process that provides flexibility in decisions based” on their expert view of regional considerations.
Id. The SDT’s proposal, however, would impose a one-size-fits-all requirement that forecloses a regional
discussion of the quantitative and qualitative considerations that may justify an exception to the proposed 75 MW
maximum capacity value. Such a regional discussion in ongoing in New England. In 2010, ISO New England
introduced to stakeholders a draft Transmission Planning Load Interruption Guideline. The Guideline noted that
load interruption should not be the principal tool to address transmission system reliability violations and
highlighted the priority of reliable service. However, applying quantitative and qualitative criteria, the Guideline
proposed for stakeholder discussion various levels of controlled load interruption in N-1-1 conditions—potentially
up to hundreds of megawatts—that may be tolerated under clearly defined conditions. NESCOE did not take a view
of the Guideline when it was presented for review and does not do so here. For now, the Guideline remains in draft
form following stakeholder comment in 2011. However, imposition of a maximum capacity threshold that is an
absolute ceiling for N-1 events and potentially, through revisions to footnote 12, N-1-1 events, would prematurely
limit important regional discussions of this issue. A better approach, and one which the Commission appears
amenable, would be to accompany any bright-line value with an exception process. There is recent precedent
supporting such an approach: NERC proposed changes to its Rules of Procedure to accommodate exceptions to the
proposed 100 kV bright-line Bulk Electric System definition. Separately, the footnote references Attachment 1 to
the respective planning standards, which requires a stakeholder process review of the utilization of planned
interruption. Such review is only triggered if utilization is sought in the Near-Term Transmission Planning Horizon,
even though the footnote permits utilization of load interruption throughout the planning horizon. NESCOE does
not support this limiting language, which is at tension with an open and transparent planning process over the
entire planning horizon. The term “Near-Term” should be stricken or further justification should be provided.
No
NESCOE appreciates the efforts of the SDT in developing a stakeholder process for considering the use of load
interruption in system planning. NESCOE especially appreciates the heightened role accorded to states in light of
jurisdictional issues raised by the prospect of shedding load and implications for retail customers. States must be
intimately involved in weighing reliability considerations against the economic implications of alternative
approaches. Regarding the language in Section I, see the comments above regarding striking “Near-Term” in this
context. NESCOE also suggests that additional clarity is needed regarding the intended meaning of “applicable
regulatory authorities or governing bodies responsible for retail electric service issues.” This language potentially
implicates state agencies beyond public utility commissions (e.g., state consumer advocates, attorneys general)
and could create confusion for state agencies as well as transmission planners that are required to provide notice
to such entities and, pursuant to Section III, provide a process for regulatory review. Instead, the SDT should
revise the language to read “electric retail regulatory authorities,” a term with clear meaning that the Commission
has itself used. See, e.g., Order 719.

Yes
NESCOE agrees with the list provided in Section II. Regarding item #7, in the interest of explicit direction, NESCOE
suggests adding at the end of the sentence the following language: “and cost comparisons of all alternatives.”
No
NESCOE is concerned that the 25 MW minimum value for regulatory review lacks sufficient technical justification.
NESCOE understands that the SDT used responses to data requests to establish this 25 MW value, which is based
on the average number of MWs that entities applying footnote “b” reported using in transmission planning. This
may be a good starting point, but additional analysis is warranted. Specifically, the analysis should consider a
more direct nexus to the system, such as substation design criteria. Additionally, as detailed above, Attachment 1
should provide clarity regarding the meaning of “applicable regulatory authorities.” Moreover, clarification is
required regarding the initial triggering factor for regulatory review. Section III states that the regulatory review
process is required before the footnote can be utilized in “Year One” of the planning horizon. Does this mean that
such regulatory review only applies to year one or does it apply to year one and beyond? If the former, NERC
needs to provide a clear rationale for restricting such review when limiting factors are already applied (i.e.,
voltages greater than 300 kV or a 25 MW minimum threshold value).
Group
Tri-State G&T
Chris Pink

1. It is not clear how transmission projects with long lead times (such as T-lines) would be handled by “Footnote
b”. In other words, it is not clear if it is acceptable for a TP to plan for shedding Firm Demand in the Near Term
Planning Horizon without meeting the conditions shown in “Attachment 1” when a mitigating project is planned
that cannot be constructed in the Near Term Planning Horizon. 2. NERC Functional Model definitions for Planning
Authorities and Transmission Planners do not include the types of activities being proposed in “Attachment 1.” As
written, this standard mandates functions on functional entities that are outside those defined by the NERC
Functional Model. 3. In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that the end-use
customer makes available to its Load-Serving Entity via contract or agreement for curtailment.” The process
described in Attachment 1 creates an agreement between stakeholders (aka “end-use customers”) and their
transmission providers for shedding Demand. Thus, if the process described in Attachment 1 is followed, the “Firm
Demand” referenced in “Footnote b” would be reclassified as “Interruptible Demand.” In essence, Firm Demand
would not be interrupted. If this was the intention of FERC, NERC, and the Drafting Team, the standard should just
state “Interruption of Firm Demand is not allowed.” 4. It is not clear how section III of “Attachment 1” would be
applied to entities that only deliver wholesale electric service and not retail electric service.
Individual
Frederick R Plett
Massachusetts Attorney General
No
Although I voted for this Footnote, I do have concerns. 1) There is no reliability benefit to the 75MVA threshold
limit. There should be no limit in the standard – it should be between stakeholders to decide that limit, not
nationally imposed. 2) Any such agreement to consider non-consequential losses should have no impact to the
BES especially when maintained in a confined boundary. 3) This takes away local decision making of PUC/ Local
Board decision making; 4) FERC's concern that a few entities would disguise the "stakeholder" process to shed
load is unfounded and should not be applied on a continent-wide basis. FERC is trying to impose tighter standards
than the industry wants.
Yes
Yes
No
The 75 MW and 25 MW limits do not belong there. It would be best if the limits were established by stakeholder
consensus and by state rulemakings.
Individual
Richard Vine
California Independent System Operator

No
While we have voted in favor of supporting the changes to the footnote and to move forward with the adoption of
the standard, we remain concerned that there is not a good foundation for concluding that loss of load over 75 MW
poses a reliability risk to the system compared to some higher MW threshold. Instead, the 75 MW capacity
threshold is simply based on the current maximum planned loss of Non-Consequential Load. While we support
minimizing reliance on Non-Consequential Load Loss, there may be scenarios where such reliance is unavoidable in
the near-term, and therefore may be needed until capital upgrades can be put in place. At a minimum, the
footnote or standard should provide for an exception process, should it be necessary for a planned NonConsequential Load Loss of greater than 75 MW.
Yes
There is no basis to support only allowing the utilization of the footnote in the Near-Term Transmission Planning
Horizon of the Planning Assessment. The footnote itself should not explicitly restrict its utilization to only the NearTerm horizon. Often, in the long-term planning horizon, when approval for transmission addition or reinforcement
cannot be obtained for a variety of reasons, utilization of the footnote is considered and adopted, subject to
stakeholder’s and regulatory authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year One) time frame and hence the proposed provision does not allow for
utilizing the footnote for the interim period before new or reinforced transmission facilities are put in place. We
suggest to remove the word “Near-Term”.
Yes
Yes
Despite a public consultation process that includes the regulator(s), the standard then calls for notification to the
regulator(s) and only moving forward once the regulator indicates that it does not oppose the shedding of load
(“once assurance has been received that…”). This is still requiring the regulator to do something, and could be
problematic if no response is provided by the regulator. How would one address silence on the part of the
regulator?
A concern with the new TPL-001-2 standard is what we see as being the elimination of the existing footnote c, the
footnote that qualified Category C load shedding as “may be necessary”. The wording under the new TPL-001-2
appears that load shedding is the unqualified expectation of the criteria for C contingencies.
Group
SERC EC Planning Standards Subcommittee
Jim Kelley
Yes
No
We recommend that up to 25 MW of planned interruption be allowed without triggering the need for a stakeholder
process. Since the average use given in the survey was 19 MW and there is no evidence of harm to the BES
reliability resulting from that use, there is no reason to require a stakeholder process for amounts less than 25
MW. This is consistent with the value cited in Section III.
No
We believe that item 1.b of Section II would contain CEII information and should have limited distribution. The
appropriate non-disclosure agreements would need to be developed to prevent widespread publication of the
information.
Yes

Individual
Randy MacDonald
NB Power Transmission
No
We disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard.
Provided there is no widespread, adverse effect on the reliability of the interconnected bulk electric system, the
effect on customers of a firm demand interruption is the responsibility of the applicable regulatory authority or its
delegated agencies responsible for local transmission and retail service over the load to be curtailed.
No
The process in Attachment 1 is overly prescriptive. Attachment 1, if retained, needs only to stipulate that the
proposed utilization of the footnote be reviewed through an open and transparent stakeholder process in
compliance with the applicable regulatory authority oversight.
No

No

Individual
Laurie Williams
Public Service Company of New Mexico
Yes
No
PNM voted yes to the Standard as a whole but would like the SDT to consider the following concern: Part II.2.b of
Attachment 1 that requires an assessment of the effect of the use of Non-Consequential Load Loss under Footnote
B on the health, safety, and welfare of the community, and PNM believes that assessments of this nature are
entirely subjective and will be difficult to comply with and even more difficult to audit. It is our belief that this
criteria should be removed from the Standard prior to its ultimate submittal to NERC.
Yes
Yes

Individual
RoLynda Shumpert
South Carolina Electric and Gas
Individual
Patrick Farrell
Southern California Edison Company
No
SCE believes that the maximum capacity threshold should be increased from 75 MW to 250 MW, as 250 MW is the
limit utilized by the California Independent System Operator (CAISO) for a consequential load drop for a single
contingency. The CAISO has a rigorous transmission planning process that allows it to plan for and permit load
shedding up to 250 MW.
Yes
The Stakeholder Process in Section I of Attachment 1 is similar to the method effectively used by the CAISO to
manage and incorporate stakeholder input in its annual transmission planning process.
No
SCE participates in the rigorous CAISO annual transmission planning process that considers the information
included in the proposed Section II of Attachment 1. However, the proposed language in Section II.2.b.
“Assessment of the effect of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community,” seems overly broad and confusing. The California Public Utility Commission (CPUC) and CAISO
presently consider these items before approving transmission plans. It is unclear what type of information would
be required in order to meet the seemingly broad request contained in Section II.2.b. SCE believes that the
language of Section II.2.b. should be removed from Attachment 1, or alternatively, the language should be revised
to specifically exempt critical loads, such as hospitals, fire department facilities, law enforcement facilities, and
correctional facilities.
No
As applied to SCE’s service territory, Section III of Attachment 1 appears to require written acknowledgement and
approval by the CPUC of each and every Firm Demand interruption authorized by the CAISO’s annual transmission
plan. In California, the CPUC is notified of and invited to every CAISO meeting on transmission planning, but the
CPUC generally does not provide specific written assurances or agreement on detailed elements of the CAISO
transmission plan. SCE believes that a general approval of the overall plan from the regulatory body should be
adequate.
Footnote “b”/Footnote 12 as currently written does not provide for an exemption to allow for the use of Firm
Demand interruption as a short-term solution to transmission problems. Many entities would benefit from being
allowed to use Footnote “b”/Footnote 12 as a temporary solution in response to construction delays until facilities
to mitigate an N-1 contingency identified in a Planning Assessment can be installed. Under the current proposal,
the stakeholder process will provide very little value in attempting to resolve such a problem. In fact, the current
Footnote “b”/Footnote 12 could result in a stakeholder process that may actually slow the implementation of
mitigation measures for the system.

Group
MEAG Power
Scott Miller
Individual
Donald Weaver
NBSO
No
We do not agree with setting a MW limit for non-consequential load loss. The allowable amount should be
determined and approved by the jurisdiction of the area(s) whose load is affected. The intent of the TPL standard
and this footnote is to ensure that if non-sequential load loss is accounted for or relied up to ensure BES reliability
(as assessed in the planning horizon), that such a decision needs to be approved by the appropriate jurisdiction.
Non-consequential load loss being applied or considered to achieve BES reliability in planning assessment is in
itself not a BES reliability concern that rises up to a continent-wide reliability standard.
No
(1) The process presented in Section I of Attachment I is overly prescriptive. This Section needs only to stipulate
that the proposed utilization of the footnote be reviewed through an open and transparent stakeholder process
developed and/or approved by the jurisdiction (a Regional Entity or regulatory authority) of the area(s) whose load
is affected area. (2) There is no basis to support allowing the utilization of the footnote in the Near-Term
Transmission Planning Horizon of the Planning Assessment only. The footnote itself should not explicitly restrict its
utilization to only the Near-Term horizon. Often, in the long-term planning horizon, when approval for transmission
addition or reinforcement cannot be obtained for whatever reasons, utilization of the footnote is considered and
adopted, subject to stakeholder’s and regulatory authority’s approvals. Note that it is impractical to add or
reinforce transmission facilities in a near-term planning (e.g. Year 0ne) time frame and hence the proposed
provision does not allow for utilizing the footnote for the interim period before new or reinforced transmission
facilities are put in place. We suggest removing the word “Near-Term”.
No
We do not agree with the need for Section II (and Attachment I as a whole) at all. The footnote, or Attachment I,
should only stipulate that when Non-Consequential Load Loss is needed to ensure that BES performance
requirements are met, then regulatory approval from local jurisdiction needs to be provided with demonstration
that the approval was obtained through an open stakeholder process.
No
See our comments under Q2 and Q3, above.
Individual
Milorad Papic
Idaho Power Company
Yes
Yes
Yes
Yes

Group
Southern Company
Antonio Grayson
Yes
No
The complex stakeholder process described in Attachment 1 should be required only if the amount of planned load
shed exceeds 25 MW or the contingency is greater than 300 kV. Since the average use given in the survey was 19
MW and there is no evidence of harm to the BES reliability resulting from that use, there is no good reason to
require such a stakeholder process for amounts less than 25 MW. The stakeholder process should only be required
for larger amounts of load.
Yes

Yes

Group
Western Area Power Administration
Brandy A. Dunn
No
We do not support a maximum threshold of 75 MW or any MW level. It is not appropriate to enforce a one size fits
all maximum value. There are no apparent reliability benefits from implementing a capacity loss limitation...why
not pick 300 MW? Also we are not sure what prompted the additional distinction of allowing the load shedding only
in the near-term planning horizon...please elaborate.
No
A public process seems out of place in a reliability standard.
Yes
No
See answer to Question 1.
Individual
Jack Stamper
Clark Public Utilities
Individual
Tom Hanzlik
SCE&G
Yes
No
No, We recommend that up to 25 MW of planned interruption be allowed without triggering the need for a
stakeholder process. Since the average use given in the survey was 19 MW and there is no evidence of harm to
the BES reliability resulting from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.
No
We believe that item 1.b of Section II may contain Critical Energy Infrastructure Information (CEII) and should
have limited distribution. The appropriate non-disclosure agreements would be required in order to prevent
widespread publication of the information.
Yes
While the current revisions improve the processes described, we have concerns regarding the revisions to TPL0021 b. SCE&G has significant concern with the proposed revision to TPL Table 1, Footnote B. The current Footnote B
states “Planned or controlled interruption of electric supply to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, may occur in certain areas without
impacting the overall reliability of the interconnected transmission systems”. The phrase “without impacting the
overall reliability of the interconnected transmission systems” is important to the TPL standards to ensure that ERO
standards do not dictate the level of service to specific customers. Service to specific customers and load pockets
is jurisdictional to State Commissions. ERO standards should not compromise this jurisdiction. SCE&G believes that
any proposed revisions to Footnote B must maintain the concept that planned or controlled interruption of electric
supply to customers, whether they are radial or network, is allowed as long as it does not impact the overall
reliability of the interconnected transmission systems. The proposed revision eliminates this concept
Individual
Kathleen Goodman
ISO New England
No
The draft footnote states that interruption “is limited to circumstances where the Non-Consequential Load Loss
meets the conditions shown in Attachment 1.” Attachment 1 appears to impermissibly require State participation
in federal transmission planning processes. Further, it places the ERO in a Transmission Planning role, which
exceeds the limits of the ERO’s functions under Section 215 of the Federal Power Act. The current language

appears to conflict with (1) federal statutes that are clear that wholesale electric transmission issues are matters
of federal, and not state, jurisdiction, (2) orders of the Federal Energy Regulatory Commission (“FERC”) regarding
the role and independence Regional Transmission Organizations (“RTOs”) with regard to transmission planning,
and (3) Section 215 which limits NERC’s authority to regulate “users, owners and operators” of the Bulk-Electric
System. Further, the conditions appear to conflict with Section 215 of the Federal Power Act by placing the ERO in
a transmission planning role and providing it with regulatory or functional oversight regarding the substance of
transmission planning decisions. The ERO has the authority to develop and enforce standards, but is not a
transmission planning entity and does not have the authority to substitute its judgment for registered Planning
Authorities and Transmission Planners regarding the planning or operation of the bulk power system. Where a
review is sought of planning entities’ determinations, per FERC-filed Tariffs, they may be brought before FERC
under Section 206 of the Federal Power Act. Because the footnote, and the associated Attachment appear to be in
conflict with FERC Tariff and other statutory provisions, they should be removed. The footnote itself states, “An
objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency events.” The objective statement within the standard does not appear to create a
requirement and should be removed.
Yes
No
Section II, 2.a states that studies must address the estimated number and type of customers affected by NonConsequential Load Shedding. This language should be removed for three reasons. (1) This appears to be
inappropriate for a reliability standard. The specific number and type of customers within a set number of MWs
that are electrically acceptable do not impact the reliability of the bulk electric system (as defined by Section 215
of the Federal Power Act). (2) Even if the number and type of affected customers were an appropriate process
question for an ERO standard, the number and type of customers may change depending on particular system
configuration at the time of the load shedding. For example, a substation may be reconfigured to address other
system issues such as maintenance and a certain number of MWs of load being interrupted, while still electrically
acceptable from a system reliability perspective, may impact different numbers and types of customers. (3)
Assuming that the number and type of customers affected were an appropriate metric, the Transmission Planner in
many cases will not be the appropriate entity to address these concerns. The Transmission Owner, Distribution
Provider or Load Serving Entities would be the appropriate entities to address customer affects. Section II, 2.b
should be revised to delete the reference to “health, safety, and welfare of the community.” It is inappropriate for
a NERC Standard to require planners to address the “health, safety, and welfare of the community.” NERC’s
authority appears limited to regulating the “reliability” of the bulk electric system. Section 215 specifies that
NERC’s authority it to establish Reliability Standards necessary to ensure an “adequate level of reliability.”
Reliability Standards may specify the “design of planned additions or modifications to such facilities to the extent
necessary to provide for reliable operation.” Section 215 defines “reliable operation” as “operating the elements of
the BPS within equipment and electrical system thermal, voltage, and stability limits so that instability,
uncontrolled separation, or cascading failures of such system will not occur as a result of a sudden disturbance,
including a cybersecurity incident, or unanticipated failure of system elements.” Establishing this requirement is
also arbitrary, because it is inconsistent with other transmission planning requirements. For example, the same
load could be shed directly as the consequence of a fault and no such assessment is required. In addition,
Transmission Planners can plan for the shedding of radial load with no assessment of health, safety and welfare.
Section II, requirements 3 and 4 discuss estimating frequency and duration of Non-Consequential Load Loss based
on historical performance. This provision is inconsistent with the manner in which transmission system planning is
conducted and should be removed. The transmission system planning process uses deterministic not probabilistic
assessments. While a power system may utilize these factors in assessing where the use of non-consequential load
loss may be acceptable in terms of providing service, these factors do not inform reliability risks to the bulk
electric system where the loss of load is found to be electrically acceptable in terms of system reliability (i.e., no
thermal, voltage, or stability issues are created or exacerbated and no instability, uncontrolled separation, or
cascading failures result).
No
This provision violates both the federal and state jurisdictional split over transmission facilities, and would violate
several FERC orders directing the independence of RTOs in the regional system planning process. Said another
way, the determinations of a federal transmission planning entity may not be required through an ERO standard to
be subject to non-jurisdictional review and approval by state entities. Further, the provision violates Section 215 of
the Federal Power Act, as the ERO cannot require the review of a particular transmission system plan by state
entities. The following language should therefore be deleted from Section III of Attachment 1: “Before a NonConsequential 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 assure that the applicable regulatory
authority or governing body responsible for retail electric service issues does not object to the use of NonConsequential Load Loss under footnote 12… .” Overall, the order of Section III is also notable. During year, two
through ten of the overall planning horizon the standard allows for Non-Consequential Load Loss without state
approval. In the first year of the assessment, approval becomes required for Non-Consequential Load Loss. In year
one, even if mandating state participation and decisional authority in a federal planning process was legally

permissible, it is too late to allow for any other alternative as transmission planning, siting and construction of
non-load loss alternatives would not be completed in the needed period. If there were non-load loss alternatives
available, the use of non-consequential load loss would not be necessary, but it would also not be part of a
transmission plan. The Regional Entities with NERC oversight perform periodic audits and require self-certification
of the planning process. By virtue of the audit and self-certification process, NERC has the ability to monitor the
use of Non-Consequential Load Loss in planning assessments. In addition to being notable for the year one timing,
Section III seems incomplete. In the case where there is objection to Non-Consequential Load Shedding, the
process appears to end without resolution. The submission to the ERO “for a determination of whether there are
any Adverse Reliability Impacts caused by the request to utilize footnote 12 for Non-Consequential Load Loss”
conflcts with federal law and orders of the Federal Energy Regulatory Commission. As noted above, the ERO is not
a planning entity and does not have authority to displace the reliability planning performed by planning entities.
Transmission planning entities are those directed by FERC to make the determinations regarding adverse reliability
impacts. If any entity wishes to challenge those determinations, it may do so before FERC under Section 215 of
the Federal Power Act. Further, this provision would conflict with orders of the FERC regarding the independence of
RTOs to conduct the regional transmission planning process. A reliability standard may not change the scope or
meaning of federal statutes nor may it contradict or collaterally attack orders of the Federal Energy Regulatory
Commission. For these reasons, this provision should be removed from the attachment to the proposed standard.
In summary, the main footnote is unobjectionable, but this standard as proposed has misplaced jurisdictional
authority under Section 215 of the Federal Power Act for both states and the ERO through several of the process
points and conditions set out in the attachment to the stardard. The removal of references is required for the
standard to comport with the law. These revisions to the standard can be made, which would then allow the draft
standard to comply with FERC’s further guidance and the other legal limitations described above.
Group
Florida Municipal Power Agency
Frank Gaffney
No
FMPA has two issues: 1. What is the technical justification for 75 MW? There is no other metric in use similar to it.
FMPA believes that, if the stakeholder process reveals that the stakeholders are willing to accept decreased service
continuity to save money on their electric bills, why should that be limited to 75 MW which has nothing to do with
BES reliability. BES reliability will not be impacted until load shedding gets near to the largest single loss of source
contingency in relation to supply / demand mismatch. Other standards have chosen the low value of 300 MW as
indicative, (e.g., CIP v5 for UFLS, EOP-004 for disturbance reporting); hence, FMPA recommends that the
maximum amount of load shedding be 300 MW. 2. The footnote should also address a process whereby the
transmission customer agrees to conditional firm service if the Transmission Planner / Transmission Service
Provider (TSP) plans on curtailing firm service to that customer following a single contingency. The TSP should not
be able to unilaterally degrade service from a state where it was not conditional to a state where it is conditional.
Yes
Yes
No
See FMPA Comments regarding the 75 MW threshold of Question 1.
Individual
Larry Watt
Lakeland Electric
Individual
Chantal Mazza
Hydro Québec TransÉnergie
No
Dropping load in the general sense should not be endorsed, but it is recognized that there are special situations
where it cannot be avoided. Provided there is no widespread, adverse effect on the reliability of the interconnected
BES, the effect of a firm demand interruption on customers is under the purview of the applicable regulatory
authority that is responsible for local transmission and retail service over the load to be curtailed, and the TPL
standard should not put a limit at 75 MW.

Even if the SDT said it is not in its scope, the following difficulty with the application of note 12 needs to be
addressed by NERC. There are no limit on non-consequential load loss for Single Contingency P2-2. and P2-3. (HV

only), multiple Contingencies P4 and P5 (HV only), and P6 and P7. The note 12 allows limited non-consequential
load loss for single contingency P1, Multiple Contingency P3. Non-consequential load loss is not allowed for P2-2
and P2-3. (EHV), and P4 and P5 (EHV). Considering the EHV Facilities, it is not reasonable to accept some nonconsequential load loss for single contingency P1 and P2-3, and then deny it for Multiple Contingency categories P4
and P5 which are statistically less frequent than the former. Also, the Multiple Contingency P7 (for which there is
no limit on non-consequential load loss) is more frequent than P2-3, P4 and P5. This technical irregularity must be
reviewed and addressed.
Individual
Kayleigh Wilkerson
Lincoln Electric System
Yes

Yes
While supportive of Section III, LES believes the language in the last paragraph could be further enhanced with
the following changes [located in brackets] to ensure a complete and accurate record is provided to the ERO.
"Once [written] assurance has been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of Non-Consequential Load Loss under
footnote 'b', the Planning Coordinator or Transmission Planner must submit the [written assurance and]
information outlined in items II.1 through II.8 above to the ERO…”.
Group
National Association of Regulatory Utility Commissioners
Holly Rachel Smith, Assistant General Counsel
No
As NARUC stated plainly in its Comments filed in FERC Docket No. RM11-18 (Dec. 20, 2011), “not only does the
law require that the States maintain authority over distribution level reliability, States are in the best position to
guide load shedding so that it has the least negative impact on the State’s customers and the operation of the
local distribution system.” Id at p. 4. Given the twin responsibilities of FERC to maintain bulk system reliability and
the states to ensure reliable and affordable service to retail load, NARUC supports the portion of the standard that
requires notification and consultation with state and local regulators. However, the maximum capacity threshold
(set at 75 MW) is problematic. In this instance, it appears that the 75 MW maximum capacity threshold is merely a
reflection of antidotal information from five data request responders and as such is not technically justified. NARUC
is not poised to offer an alternative; given that the state/local regulator is consulted in this process, the maximum
capacity threshold should just be dropped. States should be able to authorize an 80 MW exception, or whatever
level is reasonable, under specific circumstances if local economics and reliability warrant it.

No
It appears that the 25 MW minimum value is merely a reflection of antidotal information from a small number of
data request responders and as such is not technically justified. NARUC is not poised to offer an alternative; given
that the State/local regulator is consulted in this process, States should be appraised if any load is anticipated to
be shed under any planning criteria. Thus, no mimimum value should be set.
Group
Associated Electric Cooperative, Inc. - JRO00088
David Dockery - NERC Realiability Compliance Coordinator
Individual
Mark Westendorf
Midwest Independent Transmission System Operator, Inc.
No
No. We believe footnote b in NERC TPL 002-1 and/or footnote 12 in TPL-001-2 should be eliminated because the
intent of these standards is not to rely on non-consequential firm load shedding after a single contingency event.
However, if these footnotes are not eliminated, there should be some limitation on how much firm load shed is
allowed. We object to any level higher than the proposed 75 MW level and would prefer a level below 75 MW, but
won’t object to the proposed 75 MW level if the footnotes are not eliminated.
No

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our comments under Question 5.
No
No. MISO objects to a stakeholder process as outlined in Attachment 1. See our comments under Question 5.
No
No. MISO objects to a stakeholder process as outlined in Attachment 1. See our comments under Question 5.
We do not support using a stakeholder process to determine if Non-conseqeuntial Load Loss is appropriate
following a single contingency event as a means to satisfy the standard. Stakeholder processes will nearly always
result in disagreements. The parties that may be responsible for payment of upgrade costs will not necessarily line
up with the parties adversely impacted by the alternative load loss. If the stakeholder process includes all
stakeholders, there may be many more stakeholders impacted by upgrade costs based on broader benefits and/or
cost sharing than stakeholders impacted by the alternative load loss. This will result in the majority decision of a
stakeholder body to most often be one that supports load shed (until it is their turn to be the load that is shed).
On the other hand, if the stakeholder process is limited to only the stakeholders directly impacted by the proposed
load shed, to the extent those stakeholders pay only a small part of the upgrade costs, they will always select a
potentially costly upgrade to avoid load shed. The point is, we do not believe that it possible to have a fair and
impartial stakeholder process to correctly determine if and when load shed is acceptable to assist in satisfying a
single contingency standard. Since the general intents of the existing TPL-002-1 standard and proposed TPL-001-2
standard are not to rely on any shedding of non-consequenital load to meet a single contingency event, in the
event that footnote b of TPL 002-1 or footnote 12 of TPL 001-2 is not eliminated, we believe that it should be
narrowly focused only on those situations for which the original footnote was developed: interruption of service to
radial customers or some local Network customers, connected to or supplied by the Faulted element or by the
affected area, where the overall reliability of the interconnected transmission system is not impacted. We propose
that footnote b and footnote 12 be modified as follows to ensure it is not misapplied: “An objective of the planning
process is to avoid Non-Consequential Load Loss following Contingency events. In limited circumstances, NonConsequential Load Loss may be needed within the planning horizon to ensure that BES performance requirements
are satisfied. However, Non-consequential Load Loss cannot be used to avoid cascading outages or to maintain
system stability. Non-consequential Load Loss also cannot be used to avoid a thermal loading or voltage limit
violation on an EHV facility. When Non-Consequential Load Loss is utilized within the planning horizon to address
BES performance requirements, such interruption cannot exceed 75 MW and is limited to the following
circumstances: • Non-consequential Load Loss is allowed for load served by a radial transmission line to avoid
voltage limit violations on the radial transmission line following a single contingency event anywhere on the
system.. • Non-consequential load shed is allowed for load within a local area served by not more than two
transmission lines and/or transformers to avoid a thermal loading issue or voltage issue in the local area, including
the transmission lines and/or transformers supplying the area, for a loss of one of the transmission lines or
transformers supplying the area, so long as there are no thermal loading or voltage violations outside the local
area.” We believe the language above maintains acceptable reliability on the bulk electric system by limiting load
shed and violations that require load shed to radial areas or areas that would be served radially following the
single contingency. We therefore highly recommend that Attachment I be eliminated entirely and that the
footnotes either be eliminated or replaced with the modified version above.
Individual
Dan Inman
Minnkota Power Cooperative
No
1. MPC QUESTION: If a portion of the non-consequential load loss used to mitigate a contingency is controllable by
a demand side load management system, can it be excluded from the “Firm Demand interruption” in TPL-002-1c
Table I footnote ‘b’ and/or ”Non-Consequential Load Loss” in TPL-001-2a Table 1 footnote 12? a. Would this load
count towards the 25 MW and 75 MW thresholds? b. Would it have to be curtailed on a pre-contingent basis in
order to be excluded from the non-consequential load total, or can it be excluded even if the curtailment happens
through action of the UVLS? c. RECOMMENDATION: When describing “interruption of firm demand” or “nonconsequential load loss” in footnote ‘b’ add the language “not counting load shed on a pre-contingent basis”. This
would be added to the last sentence of footnote ‘b’ if it indeed should not be counted towards the 75 MW
threshold. Similar language could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW
thresholds and in TPL-001-2a as well. This would explain much more clearly what is counted towards the two
thresholds and decrease confusion. 2. MPC QUESTION: If multiple companies own portions of the nonconsequential load loss used to mitigate a contingency at a single substation, does each company’s load count
towards the 25 MW and 75 MW thresholds or does the total load at the substation count? a. EXAMPLE: 100% of
the load at a substation is set to trip with automatic UVLS. Company A, B, and C own load amounts X, Y, and Z at
the substation. i. Is the amount of load counted towards the 25 MW and 75 MW thresholds X+Y+Z, or is each
counted separately? b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’ could read “In
no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW from one entity.” Similar
language could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the two thresholds and decrease
confusion.

No
1. MPC QUESTION: In Attachment 1 Section I, what is the definition of a “stakeholder”? a. Is this intended to
apply to multiple NERC functional entities (DP, TO, TOP, LSE), public residential customers, and/or business
owners that are affected by system contingencies? b. RECOMMENDATION: Define stakeholder to be “affected
Transmission Owners, Transmission Operators, Distribution Providers, and Load-Serving Entities.” We believe it is
most appropriate for the Transmission Owners, Transmission Operators, Distribution Providers, and Load-Serving
Entities to objectively evaluate the risks of load shedding in a local area against the cost impact of a large
transmission project on the rate base. 2. MPC QUESTION: In Attachment 1 Section I item 1, what does “including
applicable regulatory authorities” refer to? a. Is this the same body that “applicable regulatory authority or
governing body” refers to in Section III? b. Are these requirements still applicable if the 25 MW threshold in
Section III is not passed? c. RECOMMENDATION: Attachment 1 Section I Item 1 could read “… including applicable
regulatory authorities or governing bodies responsible for retail electric service as described in Section III. A
clearly defined statement allows the Transmission Planner and Planning Coordinator to identify the appropriate
parties to be included in every instance Attachment 1 is used.
No
1. MPC QUESTION/COMMENT: In Attachment 1 Section II item 2b, “Assessment of the effect … on the health,
safety, and welfare of the community” is vague. Clarification is requested. a. RECOMMENDATION: Remove Item 2b
because it requires the assessment of the footnote application impact on the potential health, safety, and welfare
of the community. These types of assessments should be eliminated because they are not electric system
reliability matters and were not stipulated by FERC. In the event that the Standards Development teams choses to
keep item 2b, then add language semi-defining this as follows in Attachment 1 Section II Item 2b “...health,
safety, and welfare of the community as determined by impact on critical health and emergency services.” This
allows the Transmission Planner and Planning Coordinator to identify the appropriate parties affected by the
contingency to be analyzed in every instance Attachment 1 is used.
No
1. MPC QUESTION: In Attachment 1 Section III, what is the definition of “applicable regulatory authority or
governing body”? a. Is this the state Public Service Commission or Public Utilities Commission, the Regional
Reliability Organization (RRO), and/or the Reliability Coordinator (RC)? b. RECOMMENDATION: Depending on the
answer to the above question, define “applicable regulatory authority or governing body” more precisely. The
language could read “applicable regulatory authority or governing body responsible for retail electric service such
as the state Public Services Commission or Public Utilities Commission”. A clearly defined statement allows the
Transmission Planner and Planning Coordinator to identify the appropriate parties to be included in every instance
Attachment 1 is used. 2. MPC QUESTION: In Attachment 1, if non-consequential load loss is planned at multiple
bulk delivery points to mitigate the same contingency should the total load loss count towards the 25 MW and 75
MW thresholds or should the loads be counted individually? a. EXAMPLE: There are two load serving substations (X
load at substation B and Y load at substation C) on a long 115 kV line with 230/115 kV transformation at each end
(substation A and substation D). Automatic under-voltage load shedding is in place at substations B and C, the
UVLS relays at each substation making load trip decisions based on local voltage (i.e. independent operation). If
one end of the 115 kV line trips and 115 kV voltage is below allowable levels at both substations X and Y, then the
total load tripped by UVLS will be X+Y. i. Does the X+Y value count towards the 25 MW and 75 MW thresholds or
are X and Y counted separately? ii. What if X load is dropped for one contingency and Y load is dropped for a
different contingency, is the total load counted X+Y or each load separately? b. RECOMMENDATION: In TPL-0021c, the last sentence in Table I footnote ‘b’ could read “In no case can the planned Firm Demand interruption
under footnote ‘b’ exceed 75 MW for any single contingency.” Similar language could be added in Attachment 1
Section III in regards to the 25 MW and 75 MW thresholds and in TPL-001-2a as well. This clarification would
explain much more clearly what is counted towards the two thresholds and decrease confusion. 3. MPC
QUESTION: In Attachment 1, if UVLS relaying is programmed at a sub to trip the load in stages at multiple voltage
setpoints, such that only a fraction of the load is tripped for a given contingency, is the entirety of the load still
counted towards the 25 MW and 75 MW thresholds? a. EXAMPLE: Substation B has X load that will trip if the BES
voltage gets to 0.92 p.u. and Y that will trip if the BES voltage gets to 0.88 p.u. i. If only X amount of load is
required to mitigate a single contingency in the near-term TPL assessment, is X load counted towards the 25 MW
and 75 MW thresholds or is X+Y load counted? ii. Is there a difference if the Y load is at a different, nearby
substation with both loads having the aforementioned tripping logic? b. RECOMMENDATION: In TPL-002-1c, the
last sentence in Table I footnote ‘b’ could read “In no case can the planned Firm Demand interruption under
footnote ‘b’ (as demonstrated in the near-term horizon analysis) exceed 75 MW at a single substation.” Similar
language could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the two thresholds and decrease
confusion.
1. MPC QUESTION: In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption” or “NonConsequential Load Loss” be initiated by a manual event, such as operator action, or does it need to be automatic,
such as Under Voltage Load Shedding? a. RECOMMENDATION: In TPL-002-1c Table I footnote ‘b’, add a sentence
stating “Acceptable methods to enact Firm Demand Interruption may include manual or automatic processes that
can be initiated within a reasonable timeframe”
Individual

Bob Casey
Georgia Transmission Corp
Yes
Yes
Yes
Yes

Individual
Michael Falvo
Independent Electricity System Operator
No
We disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard.
Provided there is no adverse effect on the reliability of the interconnected bulk power system, the effect on
customers of a firm demand interruption is the responsibility of the applicable regulatory authority or its agencies
responsible for local transmission and retail service over the load to be curtailed. We propose replacing the
sentence, in the footnote and in attachment one, section III that reads: “In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is a Canadian Entity (or a Mexican Entity) should be
implemented in a manner that is consistent with/or under the direction of the Applicable Governmental Authority
or its agency in Canada (or Mexico).
No
No. The process presented in Section I is overly prescriptive. If a section that prescribes the principles of a
stakeholder process is required, then for Canadian entities this section should simply state that any threshold
should be established in a manner consistent with other service levels that apply to local transmission and retail
service for the load to be curtailed. Corrective action plans can rarely be implemented in a one-year time frame,
and in some cases, limited use of Non-consequential Load Loss will be preferable to unaffordable transmission
enhancements, therefore we believe that the use of footnote ‘b’/’12’ should not be limited to the Near-Term
Transmission Planning Horizon. We propose that the phrase “the Near-Term Transmission Planning Horizon of” be
deleted from the opening paragraph.
No
No. The process presented in Section II is overly prescriptive. If a section that prescribes the information
requirements for a stakeholder process is required, then for Canadian entities this section should simply state that
any threshold should be established in a manner consistent with other service levels that apply to local
transmission and retail service for the load to be curtailed.
No
No. The process presented in Section III is overly prescriptive and requires information not necessary to the
intended purpose. As state in Q1, we disagree with prescribing a fixed MW threshold for Non-Consequential Load
Loss in a continent-wide standard, and propose alternate language as stated in Q1 comments. If this section must
deal with a review of the use of footnote ‘b’/’12’ to ensure that there are no adverse reliability impacts on the bulk
power system, then it should be limited to the information required for that purpose. Provided there is local
support for the use of Non-Consequential Load Loss under footnote ‘b’/’12’, only information items 6 and 8 from
section II are relevant for this assessment—the remainder are not required for this section and should be deleted.
As stated in Q2 above, the use of footnote ‘b’/’12’ shouldn not be limited to the Near-Term Planning Horizon. We
propose that the words “in Year One of the Planning Assesssment”be deleted. Items 1 and 2 complicate this
section and are unneccesary. They should be replaced by a phrase such as “for those planning events where the
use of footnote ‘b’/’12’ is referenced”. We disagree with the need to submit to the ERO for a determination of
whether there are any adverse reliability impacts caused by the use of Non-Consequential Load Loss. This will
introduce a new type of review at the ERO that will create uneccesary delays and burden, and is inconsistent with
and not required for all of the other performance requirements in the TPL standards. Submitting the analysis to
the adjacent Planning Coordinators and Tranmission Planners, and any functional entity that requests it, as called
for in requirement R8 of TPL001-2 should be sufficient.
(1) We’d like to reiterate our support for allowing load interruption for a single contingency with sufficient
review/oversight and under acceptable conditions, including no adverse impact on the reliability of the
interconnected bulk power system. The reliability aspects (BES performance requirements) should be reviewed for
acceptability by the adjacent Planning Coordinators and Transmission Planners. However, issues pertaining to

economics or externalities which may not be directly reliability-related are always available for review and debate
by the stakeholders via the regulatory processes and subject to approval by the regulatory authority of each
jurisdiction (including those in Canada and Mexico). (2) Furthermore, we request that Table 1 of TPL-001-3
(previous TPL-001-2 approved by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to
allow the application of footnote ‘b’/’12’ that is allowed for the P1 events. Events in P2, P4, and P5 can involve
more elements and can be more onerous and stressful to the system than the P1 events, and if use of footnote
‘b’/’12’ is permitted in the less stressful P1 events, it should also be permitted in P2, P4 and P5 events. (3) We
suggest that NERC Standards and their requirements should focus on what is the anticipated outcome rather than
how to achieve it. Accordingly, we believe that the focus of footnote ‘b’, and footnote 12 should be that
interruption of load must not have an adverse impact on the reliability of the interconnected bulk power system. A
continent-wide standard should not concern itself with the reliability of supply or supply continuity for local load, as
that is the responsibility of the applicable regulatory authority or its agencies responsible for local transmission and
retail service over the load to be curtailed. As mentioned above, NERC Standards and their requirements should
focus on what is the anticipated outcome rather than how to achieve it. In this regard, we believe that Attachment
1 is not necessary because it prescribes a process which goes beyond the outcome of the standard and dictates
how stakeholdering must be carried out. The individual jurisdiction should establish the process for ensuring
compliance with the standard and decide to what extent a stakeholdering process is necessary to establish the
acceptable level of load rejection for the area in a manner consistent with local transmission established service
levels.
Group
National Grid
Michael Jones
No
The 75MW of Firm Demand interruption is retail load that is being dropped. Dropping load in the general sense
should not be endorsed, but it is recognized that there are special situations where it cannot be avoided. If a
regulator responsible for retail load is comfortable with greater than 75MW being dropped in a rare situation, there
should not be a requirement to build out of the situation. Provided there is no widespread, adverse effect on the
reliability of the interconnected BES, the effect of a firm demand interruption on customers is under the purview of
the applicable regulatory authority that is responsible for local transmission and retail service over the load to be
curtailed. There is no technical basis for the 75 MW figure with respect to reliability impact. Although, the value
was developed by the SDT as a result of their review of Section 1600 Data Request, there was no reliability based
analysis performed to identify whether the 75 MW is reasonable number. It is possible that a number either larger
or lower could be identified if a reliability and cost-effective analysis is conducted.

No
The current document includes the language: 2. The planned Non-Consequential Load Loss under footnote 12 is
greater than or equal to 25 MW. This gives no concept of how long customers could expect to be out of service and
hence whether this would be an appropriate approach. Suggest using a value that is based on energy, i.e., MWh. A
value of 600MWh would represent 25 MW out for 24 hours, or could be 60 MW out for 10 hours, etc. This would
seem to provide a more valuable understanding the true impact to customers in assessing the health, safety and
welfare. It is also expected that if Demand Resources are being used that they would be excluded from the term
“non-consequencial” load, and that the value being discussed is only that in addition to any Demand Resources
being used.
Group
Iberdrola USA
John Allen
No
“Contingency events” should be replaced by “Planning Events.” Why would load shedding be limited only for
certain circumstances in the Near-Term Transmission Planning Horizon? The Near Term is likely the period when
the least can be done to avoid load shedding due to the time required for permitting and construction of facilities.
A maximum capacity threshold is reasonable, whether 75 MW or a lower value.
No
“Stakeholders” is undefined – would this be the same stakeholder body identified in the planning process of the
Open Access Transmission Tariff?
No
Regarding the documentation required for item 2.b, how are “health, safety, and welfare of the community” to be
assessed? What are the metrics? How would compliance with this provision be evaluated?
No
Why would a retail service regulator approve a 300 kV and above performance issue?

A one-paragraph footnote encompassing a 2-page attachment is cumbersome for a Reliability Standard.
Group
ACES Power Marketing Standards Collaborators
Ben Engelby
No
(1) We disagree with placing an upper limit on the amount of firm load shed. Conceptually, it seems like a good
idea but we do not believe that such a threshold could ever consider all of the potential issues that could arise and
would cause the need to plan to shed firm load. This is especially true considering that the SAR clarifies that the
upper threshold will be based on the existing planned load shedding values. Future issues cannot be considered by
the information contained in the data request. Consider a situation in which a new transmission line was included
in Planning Assessment but cannot be built because right of ways cannot be obtained. Should an upper limit be
placed on planned load shed in such a situation? (2) We disagree with the threshold of 75 MW. In Order No. 762,
the Commission discussed the “blend concept,” where it “envisioned the planner would consider up to 100 MW of
planned Firm Demand interruption along with other options to resolve the system performance criteria violation
and submit its documentation and explanation to the entity deciding whether the planned load shed is acceptable.”
(emphasis added) Even the Commission envisioned using higher thresholds. Furthermore, the data appears to
show that one instance of Non-Consequential Load Loss would be immediately out of compliance because it is
actual 75.2 MW not 75 MW. If the upper threshold is too close to 75 MW, any load growth might also compel the
instance to be disqualified. If the SDT plans to keep the upper limit, we suggest increasing the amount to at least
100 MW.
No
(1) Many RTOs have well organized stakeholder processes that could be utilized to satisfy Attachment 1. Because
the TPL standards apply to both the PC and TP, one may conclude that both functions need to have a stakeholder
process. Rather, we think that the TP should be able to rely on its PC’s stakeholder process. We recommend
clarifying Attachment 1 that it is acceptable for the TP to rely on the PC’s process and that both entities are not
required to have redundant processes. The most important point is that stakeholders have an opportunity to
participate.
No
(1) Adding the word “effect” on the health, safety, and welfare of the community creates more confusion regarding
what is needed for the assessment. We recommend removing the effect clause from Section II. (2) We disagree
that the Transmission Planner should be required to provide an assessment at all on the health, safety and welfare
of the community. Attachment 1, Section 2a identifies the types of customers that are impacted without needing a
formal assessment. Stakeholders will have an opportunity to provide information on impacts of planned load
shedding through either the Transmission Planner’s stakeholder comment process or through the local regulatory
agency’s stakeholder comment process. Further, these planned interruptions of firm demand are expected to be
short in nature so any impact would be de minimis. Finally, an assessment on the health, safety and welfare of the
community is an unnecessary burden on the registered entity and is better suited for local governments that can
speak through the stakeholder process. (3) Bullet 3 is based on available historical information. While this seems
reasonable, we have concerns because of the rare instances that Non-Consequential Load Shed actually occurs. If
a TP uses Non-Consequential Load Shed for the first time, there is no historical information. What would be an
acceptable basis for the first use of Non-Consequential Load Shed when the entity is without historical
information? (4) Expected time duration of the planned load shed is too speculative and should not be required
because any duration will likely be a guess. When actual contingencies occur, the time of restoration varies and
any time that was selected prior to the event is not likely to be correct. We do not see the value in predicting the
duration time because there is too much uncertainty about how long an outage will really last. The SDT needs to
clarify what is expected for the duration of the planned load shed. (5) While we appreciate that the response to
our comments clarified the intent is that “Possible future plans could include a decision not to mitigate the need for
Firm Demand interruption,” the language in the Attachment simply does not reflect this. The Attachment
specifically states “Future plans to mitigate the need for Non-Consequential Load Loss.” A decision not to mitigate
the need for Firm Demand interruption is not a future plan to mitigate. Consequently, Attachment 1, section II.5
will need to be modified to implement this intent. Otherwise, this language is certain to be interpreted as requiring
a mitigation plan.
No
(1) We disagree with the threshold of 75 MW, as mentioned above.
(1) The SDT needs to consider the connection between the developing standards to maintain and improve
reliability with the costs required to meet those standards. We believe there is an imbalance of the costs
associated with meeting compliance for the current draft standard with proposed benefit of maintaining reliability
of the BPS. This standard is a good candidate for the CEAP initiative to determine the cost benefits of reliability.
(2) The standard needs to allow more flexibility regarding the use of planned load shed to address transmission
performance issues in the planning horizon. It needs to recognize that these planned load shedding events may
only be preliminary decisions for addressing problems that are several years away. If there is little chance that the
planned shed load will ever be relied upon in the operating time horizon, there should be much less stringent
requirements. For instance, if a PC or TP relies on planned load shed for year five of the planning horizon but year

one does not utilize the planned load shed, they have four years to develop another solution. Why should an entity
expend great effort and resources for year five when another solution will likely be developed within that time
period? (3) What does “materially changed” mean and what degree of a change would be considered material in
the Attachment 1 stakeholder process? The SDT should clarify specific conditions in Section II that would
constitute a material change. (4) Thank you for the opportunity to comment.
Individual
Richard Bachmeier
Gainesville Regional Utilities
Individual
Spencer Tacke
Modesto Irrigation District
No
I am voting NO because there is no technical basis for use of the 75 and 25 MW absolute threshold values,
regardless of the size of the utility's load, referenced in the proposed standard. WECC's past experience with
implementation of arbitrary magnitudes for requirements (e.g., the 5% and 7% arbitrary magnitude contingency
reserve requirements), has proved to be problematic. I would suggest investigating a technical basis for using a
relative requirement, such as percentage of the utility's load, maybe 5% and 2.5%, respectively, and that it be
based on technical requirements similar to those found in Table 1 of the WECC Criteria TPL-001-WECC-CRT-2.
Thank you.
Yes
Yes
No
I am voting NO because there is no technical basis for use of the 75 and 25 MW absolute threshold values,
regardless of the size of the utility's load, referenced in the proposed standard. WECC's past experience with
implementation of arbitrary magnitudes for requirements (e.g., the 5% and 7% arbitrary magnitude contingency
reserve requirements), has proved to be problematic. I would suggest investigating a technical basis for using a
relative requirement, such as percentage of the utility's load, maybe 5% and 2.5%, respectively, and that it be
based on technical requirements similar to those found in Table 1 of the WECC Criteria TPL-001-WECC-CRT-2.
Thank you.
Individual
Jason Weiers
Otter Tail Power Company
Individual
Alice Ireland
Xcel Energy
No
Although the maximum capacity value is used for planning purposes, how does this correlate with operational
standards/issues that may require that value be greater. The planning studies look at very specific seasonal
conditions on the system and may not necessarily look at all the states of the transmission system during the
normal business day. If an operational event requiring a greater value of Non-Consequential Load Loss (NCLL) is
executed and the specific outage was not considered in a planning study, how will this affect compliance with the
planning standard. There was no technical rationale by the SDT for selecting the maximum value, thus a limit
should not be set and should be left as a general discussion issue in the Stakeholder Process due to the many
unforeseen issues that may arise.
Yes
The possibility of NCLL is always present, whether in the planning or operational arena. Section I (#5) should
however specifically state that in the dispute resolution process a stakeholder does not have right of refusal for
NCLL. This should be especially true when a transmission project has been proposed and NCLL in the interim is
required due to the regulatory process, equipment lead time, etc. preventing the completion of project at an
earlier time.
No
Section II should be left as part of the resolution in the dispute process and should not be made a requirement.
Some in particular include: § II.1. - this should be based only on applicable contingencies or conditions that could
require NCLL. Having to include the estimated hours at or above a load level may not always be the most effective
way to convey why NCLL will be used and adds little to the argument of why or why not it needs to be used. §
II.2.a - This may not always be apparent to the TO serving a wholesale transmission customers (REC, MUNICIPAL,

etc.). This should be eliminated since it does little in emphasizing the need for NCLL. § II.2.b - The "effect" of the
use of NCLL may not always be apparent, because it is a perceived condition of what could happen that can be
interpreted differently. I agree that it should be mentioned in the Stakeholder process outlining the locations
where NCLL will take place and let the dispute process identify and assess the health, safety and welfare of the
community. How do you assess the effect in the Planning of NCLL. The effect should be identified by the party
being affected and resolved in the dispute process. § II.3 & 4. - This needs to be eliminated. Expected frequency
and duration of NCLL based on historical performance DOES NOT GUARANTEE future performance and does little in
emphasizing the need for NCLL. II.8 - This should be addressed by the Regional Planning Authority in their
regional studies.
No
It does not appear that an entity has any options if the applicable regulatory authority or governing body objects
to the use of NCLL in year one. This could potentially occur as a result of load patterns and generation issues
submitted by an LSE not necessarily having BES elements and the only solution is to implement NCLL. In year one,
it is too late to build any necessary and NCLL may be the only alternative.
Setting limits on the amount of NCLL only sets the stage for failure in the compliance of NERC standards and fails
to take note of what is really the issue; the planning of a transmission system that is both reliable and
economically viable for all stakeholders and customers. It should be emphasized that the use NCLL in a “planning
process” is only assuming the conditions set in the study will exist and in no way reflects the conditions seen
during the day to day operation of the transmission system. Xcel Energy is concerned about the previous ability on
loss of load in anticipation of the next outage (previously C3 now P6). For TPL-003, loss of load in anticipation of
the next system outage was covered under footnote B. Footnote 9 now states, “…the re-dispatch does not result in
any Non-Consequential Load Loss. “ This is a large increase in requirements of the transmission system to
operate. As written, it appears that footnote 12 is NOT applicable to P6 contingencies. Please clarify is this is the
intent.

Consideration of Comments

Project Revision of TPL-002 footnote ‘b’ and TPL-001 footnote 12
The Project 2010-11 Drafting Team thanks all commenters who submitted comments on the proposed
standards, TPL-002-1c and TPL-001-2a. The standards were posted for a 45-day public comment
period from October 5, 2012 through November 19, 2012 with the initial ballot period from November
9, 2012 to November 19, 2012. There were 61 sets of comments, including comments from
approximately 149 different people from approximately 112 companies representing 9 of the 10
Industry Segments as shown in the table on the following pages.
All comments submitted may be reviewed in their original format on the standard’s project page.
Summary: The drafting team made the following revisions in response to comments:
TPL-002-1c: footnote b - It is recognized that Firm For purposes of this footnote, the following
are not counted as Firm Demand will be interrupted if it is: (1) Demand directly served by the
Elements removed from service as a result of the Contingency, orand (2) Interruptible Demand
or Demand-Side Management Load.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and
magnitude of Non-Consequential Load Loss following Contingency planning events.
TPL-001-2a: footnote 12 - 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.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand
interruption under footnote ‘b’ on the health, safety, and welfare of the community
Section II, Bullet #5. Future plans to mitigate alleviate the need for Firm Demand interruption
under footnote ‘b’
Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as
an element of a Corrective Action Plan in Year One of the Planning Assessment, the
Transmission Planner or Planning Coordinator must assure ensure that the applicable regulatory
authority authorities or governing bodybodies responsible for retail electric service issues does
not object to the use of Firm Demand interruption under footnote ‘b’ if either:

Section III, last paragraph: Once assurance has been received that the applicable regulatory
authority authorities or governing bodybodies responsible for retail electric service issues does
not object to the use of Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.

A number of respondents continue to question the legality of the proposed standards. The general line
of thought in those comments is that NERC is imposing itself into the local planning process in violation
of existing statutes. The SDT does not believe that to be the case and has responded accordingly to
those commenters.
Many commenters questioned the use of a stakeholder process at all. Those commenters expressed
the opinion that the FERC Order did not mandate the use of the stakeholder process. The SDT used the
Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard;
not because it contained a stakeholder process, but because the process was not well defined, did not
include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure
that BES reliability would be maintained. The balloted draft added detail and specificity to the already
approved approach.
In addition, many commenters chose to question already approved facets of the proposed TPL-001-2a
standard. These commenters are questioning the application (or non-application) of footnote 12 for
various planning events. TPL-001-2 was previously approved by the industry and the NERC Board of
Trustees. The SAR for this project took that approval as the starting point for the specific discussion of
footnote ‘b’/12 and does not allow for review of previously approved applications of the footnote.
The SDT is requesting that the project be moved to a successive ballot.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11

2

Index to Questions, Comments, and Responses
1.

Do you agree with the text in the body of the footnote including the maximum capacity threshold?
If you do not support these changes or you agree in general but feel that alternative language
would be more appropriate, please provide specific suggestionsin your comments. For the
maximum capacity item, please supply any technical rationale for your comment along with
limiting conditions and any current criteria in use at your entity. ..................................................13

2.

Do you agree with the description and components of the the Stakeholder Process in Section I of
Attachment 1? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ........................................................................................................................................46

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II
of Attachment1? If you do not support these changes or you agree in general but feel that
alternative language would be more appropriate, please provide specific suggestions in your
comments. ........................................................................................................................................60

4.

Do you agree with the text in Section III of Attachment 1? If you do not support these changes or
you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments............................................................................................76

5.

If you have any other comments on this Standard that you haven’t already mentioned above,
please provide them here: ............................................................................................................ 100

Consideration of Comments: Project 2010-11

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Guy Zito

Additional Member

Northeast Power Coordinating Council
Additional Organization

Region

Segment
Selection

1.

Alan Adamson

New York State Reliability Council, LLC

NPCC

10

2.

Carmen Agavriloai

Independent Electricity System Operator

NPCC

2

3.

Greg Campoli

New York Independent System Operator

NPCC

2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC

1

5.

Chris de Graffenried

Consolidated Edison Co. of New York, Inc. NPCC

1

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC

10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC

5

8.

Kathleen Goodman

ISO - New England

NPCC

2

9.

Christina Koncz

PSEG Power LLC

NPCC

5

Consolidated Edison Co. of New York, Inc. NPCC

3

10. Peter Yost

2

3

4

5

6

7

8

9

10

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

11. Michael Lombardi

Northeast Utilities

NPCC

1

12. Randy MacDonald

New Brunswick Power Transmission

NPCC

9

13. Bruce Metruck

New York Power Authority

NPCC

6

14. Silvia Parada Mitchell

NextEra Energy, LLC

NPCC

5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC

10

16. Robert Pellegrini

The United Illuminating Company

NPCC

1

17. Si-Truc Phan

Hydro-Quebec Transenergie

NPCC

1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC

5

19. Brian Robinson

Utility Services

NPCC

8

20. Ben Wu

Orange and Rockland Utilities

NPCC

1

21. Wayne Sipperly

New York Power Authority

NPCC

5

22. Donald Weaver

New Brunswick System Operator

NPCC

2

2.

Group

Southwest Power Pool Reliability Standards
Development Team

Jonathan Hayes

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Jonathan Hayes

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

3. John Allen

City utilities of springfield SPP

1, 4

4. Don Taylor

Westar Energy

SPP

1, 3, 5, 6

5. Bo Jones

Westar Energy

SPP

1, 3, 5, 6

3.

Group

WILL SMITH

MRO NSRF

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

OPPD

MRO

1, 3, 5, 6

3.

TOM BREENE

WPS

MRO

3, 4, 5, 6

4.

JODI JENSON

WAPA

MRO

1, 6

5.

KEN GOLDSMITH

ALTW

MRO

4

6.

ALICE IRELAND

XCEL

MRO

1, 3, 5, 6

7.

DAVE RUDOLPH

BEPC

MRO

1, 3, 5, 6

8.

ERIC RUSKAMP

LES

MRO

1, 3, 5, 6

9.

JOE DEPOOTER

MGE

MRO

3, 4, 5, 6

2.

Consideration of Comments: Project 2010-11

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

10. SCOTT NICKELS

RPU

MRO

4

11. TERRY HARBOUR MEC

MRO

1, 3, 5, 6

12. MARIE KNOX

MISO

MRO

2

13. LEE KITTELSON

OTP

MRO

1, 3, 5

14. SCOTT BOS

MPW

MRO

1, 3, 5, 6

15. TONY EDDLEMAN NPPD

MRO

1, 3, 5

16. MIKE BRYTOWSKI GRE

MRO

1, 3, 5, 6

17. DAN INMAN

MPC

MRO

1, 3, 5, 6

4.

paul haase

Group

Seattle City Light

2

3

X

X

X

X

4

X

5

6

X

X

X

X

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. pawel krupa

seattle city light

WECC 1

2. dana wheelock

seattle city light

WECC 3

3. hao li

seattle city light

WECC 4

4. mike haynes

seattle city light

WECC 5

5. dennis sismaet

seattle city light

WECC 6

5.

Group

Greg Rowland

Duke Energy

Additional Member Additional Organization Region Segment Selection
1. Doug Hils

Duke Energy

RFC

1

2. Lee Schuster

Duke Energy

FRCC

3

3. Dale Goodwine

Duke Energy

SERC

5

4. Greg Cecil

Duke Energy

RFC

6

6.

Group

Chris Higgins

Bonneville Power Administration

Additional Member Additional Organization Region Segment Selection
1. Chuck Matthews

Transmission Planning

WECC 1

2. Berhanu Tesema

Transmission Planning

WECC 1

3. Melvin Rodrigues

Transmission Planning

WECC 1

7.

Group

Chris Pink

Tri-State G&T

X

Additional Member Additional Organization Region Segment Selection
1. Chris Pink
2. Mark Stein
3. Janelle Gill

Consideration of Comments: Project 2010-11

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2

3

4

5

6

7

4. Bill Middaugh

8.

Group

Jim Kelley

Additional Member

SERC EC Planning Standards Subcommittee

Additional Organization
Ameren Services Co

SERC

1

2. Charles Long

Entergy Services

SERC

1

3. Edin Habibovich

Entergy Services

SERC

1

4. James Manning

NC Electric Membership Corp. SERC

1

5. Bob Jones

Southern Company Services

1

Group

X

Region Segment Selection

1. John Sullivan

9.

X

SERC

Scott Miller

MEAG Power

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Steve Grego

MEAG Power

SERC

5

2. Steve Jackson

MEAG Power

SERC

3

3. Danny Dees

MEAG Power

SERC

1

10.

Group

Frank Gaffney

Florida Municipal Power Agency

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

Tim Beyrle

City of New Smyrna Beach FRCC

4

2.

Jim Howard

Lakeland Electric

FRCC

3

3.

Greg Woessner

Kissimmee Utility Authority FRCC

3

4.

Lynne Mila

City of Clewiston

FRCC

3

5.

Joe Stonecipher

Beaches Energy Services FRCC

1

6.

Cairo Vanegas

Fort Pierce Utility Authority FRCC

4

7.

Randy Hahn

Ocala Utility Service

FRCC

3

8.

Stan Rzad

Keys Energy Services

FRCC

1

11.

Group

David Dockery - NERC
Realiability Compliance
Coordinator
Additional Member

Associated Electric Cooperative, Inc. JRO00088

Additional Organization Region Segment Selection

1. Central Electric Power Cooperative

SERC

1, 3

2. KAMO Electric Cooperative

SERC

1, 3

3. M & A Electric Power Cooperative

SERC

1, 3

4. Northeast Missouri Electric Power Cooperative

SERC

1, 3

Consideration of Comments: Project 2010-11

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5. N.W. Electric Power Cooperative, Inc.

SERC

1, 3

6. Sho-Me Power Electric Cooperative

SERC

1, 3

12.

Group

Michael Jones

Additional Member
1. Michael Schiavone

13.

Additional Organization

Group

John Allen

Additional Member

Additional Organization

New York State Electric & Gas NPCC 1

8

9

X

ACES Power Marketing Standards
Collaborators
Additional Organization

X

Region

Segment
Selection

Sunflower Electric Power Corporation

SPP

1

2. Mike Brytowski

Great River Energy

MRO

1, 3, 5, 6

3. Amber Anderson

East Kentucky Power Cooperative

SERC

1, 3, 5

4. John Shaver

Arizona Electric Power Cooperative/Southwest Transmission
Cooperative, Inc.

WECC 1, 4, 5

5. Shari Heino

Brazos Electric Power Cooperative, Inc.

ERCOT 1, 5

6. Bob Solomon

Hoosier Energy Rural Electric Cooperative, Inc.

RFC

1, 3, 4, 5

Tim Ponseti, VP

TVA Transmission Reliability Engineering
and Controls

X

Individual

16.

Individual

Janet Smith

Arizona Public Service Company

17.

Individual

Antonio Grayson

Southern Company

X
X

18.

Individual

Western Area Power Administration

X

Individual

Brandy A. Dunn
Holly Rachel Smith,
Assistant General
Counsel

Individual

Thad Ness

Individual

Kenn Backholm

21.

7

X

1. Megan Wagner

20.

6

NPCC 1

Ben Engelby

Additional
Member

19.

5

Region Segment Selection

2. Raymond Kinney

15.

4

Region Segment Selection

Iberdrola USA

Central Maine Power

Group

3

Niagara Mohawk (A National Grid Company) NPCC 3

1. Joseph Turano

14.

X

National Grid

2

X
X
X

X
X

X
X
X
X

National Association of Regulatory Utility
Commissioners
American Electric Power
Public Utility District No.1 of Snohomish
County

Consideration of Comments: Project 2010-11

X

X

X

X

X

X

X

X

X

X

8

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

22.

Individual

X

Travis Metcalfe

Tacoma Power

Individual
24. Individual

Steven R. Wallace
Nazra Gladu

Seminole Electric Cooperative, Inc.
Manitoba Hydro

X

25.

Individual

James Tucker

Deseret Generation & Transmission

X

26.

Individual

Melissa Kurtz

X

23.

Individual

Chris Pink

USACE
Tri-State Generation & Transmission
Association

28.

Individual

Andrew Z. Pusztai

American Transmission Company

X

29.

Individual

John Collins

Platte River Power Authority

X

30.

Individual

Don Jones

Texas Reliability Entity

31.

Individual

Kirit Shah

Ameren

32.

Individual

Cheryl Moseley

Electric Reliability Council of Texas, Inc.

33.

Individual

David Kiguel

Hydro One Networks Inc.

X

34.

Individual

Martyn Turner

LCRA Transmission Service Corporation

X

35.

Individual

Joe Tarantino

Sacramento Municipal Utility District

X

36.

Individual

Patricia Robertson

BC Hydro and Power Authority

X

37.

Individual

Terry Harbour

MidAmerican Energy Company

38.

Individual

Andrew Gallo

Individual

Jason Marshall

City of Austin dba Austin Energy
New England States Committee on
Electricity (NESCOE)

Individual

Frederick R Plett

Massachusetts Attorney General

Individual
42. Individual

Richard Vine
Randy MacDonald

California Independent System Operator
NB Power Transmission

43.

Individual

Laurie Williams

Public Service Company of New Mexico

44.

Individual

RoLynda Shumpert

45.

Individual

Patrick Farrell

27.

39.
40.
41.

2

3

4

5

6

X

X

X

X

X

X

X

X

X

X

X

8

9

10

X
X

X

X

X
X

X

X

X

X

X

X

X
X
X
X

X

X

X

X

X

X

X

X

X

X

X

X
X
X

South Carolina Electric and Gas

X
X

X
X

X

X

Southern California Edison Company

X

X

X

X

Consideration of Comments: Project 2010-11

7

9

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

46.

Individual

2

3

4

5

NBSO

Individual
48. Individual

Milorad Papic
Jack Stamper

Idaho Power Company
Clark Public Utilities

X

49.

Individual

Tom Hanzlik

SCE&G

X

50.

Individual

Kathleen Goodman

ISO New England

51.

Individual

Larry Watt

Lakeland Electric

X

52.

Individual

Chantal Mazza

Hydro Québec TransÉnergie

X

53.

Individual

Kayleigh Wilkerson

X

Individual

Mark Westendorf

Lincoln Electric System
Midwest Independent Transmission System
Operator, Inc.

55.

Individual

Dan Inman

Minnkota Power Cooperative

X

56.

Individual

Bob Casey

Georgia Transmission Corp

X

57.

Individual

Michael Falvo

Independent Electricity System Operator

58.

Individual

Richard Bachmeier

Gainesville Regional Utilities

59.

Individual

Spencer Tacke

Modesto Irrigation District

60.

Individual

Jason Weiers

Otter Tail Power Company

X

X

X

61.

Individual

Alice Ireland

Xcel Energy

X

X

X

54.

Consideration of Comments: Project 2010-11

7

X

Donald Weaver

47.

6

X

X
X

X

X

X

X

X

X

X

X
X
X
X

10

8

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: The SDT thanks you for your participation. Your support of comments from another organization has been
noted.
Organization

Supporting Comments of “Entity Name”

Seattle City Light

Puget Sound Energy

MEAG Power

Snohomish County Public Utility District

Associated Electric Cooperative, Inc. - JRO00088

SERC EC Planning Standard Subcommittee

USACE

MRO NSRF

MidAmerican Energy Company

MidAmerican supports the NSRF comments

City of Austin dba Austin Energy

Tacoma Power and Snohomish P.U.D.

South Carolina Electric and Gas

South Carolina Electric and Gas - SCE&G

Clark Public Utilities

Snohomish County PUD and Tacoma Power.

Lakeland Electric

FMPA

Consideration of Comments: Project 2010-11

11

Organization

Supporting Comments of “Entity Name”

Gainesville Regional Utilities

FMPA - Florida Municipal Power Agency

Otter Tail Power Company

Minnkota Power Cooperative

Consideration of Comments: Project 2010-11

12

1.

Do you agree with the text in the body of the footnote including the maximum capacity threshold? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate, please provide specific
suggestions in your comments. For the maximum capacity item, please supply any technical rationale for your comment along
with limiting conditions and any current criteria in use at your entity.

Summary Consideration: The majority of the comments received for this question were handled with explanations of the SDT intent or
clarifications of the constraints under which the SDT was working. There were a number of comments however concerning the
justification of the threshold values. The remand order from FERC requested that a Section 1600 data request be made to provide data
on the actual usage of footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a
maximum value for the amount of Load that could be planned to be shed under footnote ‘b’. DOE and other thresholds can be a point
of reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any
deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach.
There were several comments regarding the application of footnote 12 within Table 1 of proposed TPL-001-2a. Such discussion is out of
scope for this project as defined in the Standards Authorization Request (SAR). TPL-001-2 has been approved by the industry through
the standards development process and by the NERC Board of Trustees. Nothing in this project affects where footnote 12 is applied
within Table 1. The only change being proposed is to the details of how to utilize footnote 12 as shown in the proposed Attachment 1.
The following clarifications to language were made due to comments received:
TPL-002-1c: footnote b) It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load
Loss following Contingency planning events.
TPL-001-2a: footnote 12 - 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.
Organization

Yes or No

Consideration of Comments: Project 2010-11

Question 1 Comment

13

Organization

Yes or No

MRO NSRF

No

USACE

Question 1 Comment
(1) Change the wording at the end of the first sentence from “following
Contingency events” to “following Contingency events and Contingency
events during the planned (maintenance) outage of any bulk electric
equipment)”. This would remind Transmission Planners and Planning
Coordinators to include the consideration of planned outages at demand
levels for which the outage would be performed.
(2) Raise the maximum load dropping threshold for the footnote from 75
MW to 100 MW. A 100 MW threshold is reasonable because the DOE uses
the intentional dropping of more than 100 MW as one of the thresholds
for determininge when enough load is dropped to justify a formal system
event analysis.
(3) Add a sentence at the end of the footnote to read, “This footnote
does not apply to any load that is not NERC registered (e.g. load that does
not meet the greater than 25 MW NERC registration criterion).
(4) If a portion of the non-consequential load loss used to mitigate a
contingency is controllable by a demand side load management system,
can it be excluded from the “Firm Demand interruption” in TPL-002-1c
Table I footnote ‘b’ and/or “Non-Consequential Load Loss” in TPL-001-2a
Table 1 footnote 12? Does it have to be curtailed on a pre-contingent
basis in order to be excluded from the non-consequential load total, or
can it be excluded even if the curtailment happens through action of the
UVLS? Does this load count towards the 25 MW and 75 MW thresholds?
RECOMMENDATION: When describing “interruption of firm demand” or
“non-consequential load loss” in footnote ‘b’ add the language “not
counting load shed on a pre-contingent basis”. This would be added to the
last sentence of footnote ‘b’ if it indeed should not be counted towards
the 75 MW threshold. Similar language could be added in Attachment 1
Section III in regards to the 25 MW and 75 MW thresholds and in TPL-001-

Consideration of Comments: Project 2010-11

14

Organization

Yes or No

Question 1 Comment
2a as well. This would explain much more clearly what is counted towards
the two thresholds and decrease confusion.
(5) If multiple companies own portions of the non-consequential load loss
a used to mitigate a contingency at a single substation does each
company’s load portion count towards the 25 MW and 75 MW thresholds
or does the total load at the substation count? For example, 100% of the
load at a substation is set to trip with automatic UVLS. Company A, B, and
C own load amounts X, Y, and Z at the substation. Is the amount of load
counted towards the 25 MW and 75 MW thresholds X+Y+Z, or is each
counted separately?
RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote
‘b’ could read “In no case can the planned Firm Demand interruption from
under footnote ‘b’ exceed 75 MW from one entity.” Similar language
could be added in Attachment 1 Section III in regards to the 25 MW and
75 MW thresholds and in TPL-001-2a as well. This would explain much
more clearly what is counted towards the two thresholds and decrease
confusion.

Response: (1) The SDT intended the first sentence to be a fundamental statement of planning principle and thus believes that the
suggested wording is redundant and therefore not required. Consideration of planned outages at demand levels for which the
outage is performed is covered in proposed TPL-001-2a, Requirement R1 where it is stated that models must represent actual System
conditions as well as in Requirement R2, Part 2.1.3 which clearly states that analysis is to be done when known outages are
scheduled. No change made.
(2) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
(3) Load that is served from the entity’s transmission system is considered as applicable Load in this standard regardless of the
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underlying registration situation. No change made.
(4) Proposed TPL-002-1c states in the footnote that: “It is recognized that Firm Demand will be interrupted if it is: (1) directly served
by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side Management
Load” (emphasis added). This makes it clear that Demand-Side Management Load is not to be considered as Non-Consequential
Load. In proposed TPL-001-2a, the proposed definition of Non-Consequential Load includes the term ‘Interruptible Load’ which as
defined in the NERC Glossary includes demand to be curtailed that the end-use customer makes available through contract or
agreement. Thus, the concept is covered in proposed TPL-001-2a as well. However, upon reviewing the comments, the SDT has seen
that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
(5) “Ownership” of the Non-Consequential Load Loss is not a relevant factor; all thresholds mentioned in the footnote are related to
the total Non-Consequential Load Loss. No change made.
ACES Power Marketing Standards
Collaborators

No

(1) We disagree with placing an upper limit on the amount of firm load
shed. Conceptually, it seems like a good idea but we do not believe that
such a threshold could ever consider all of the potential issues that could
arise and would cause the need to plan to shed firm load. This is
especially true considering that the SAR clarifies that the upper threshold
will be based on the existing planned load shedding values. Future issues
cannot be considered by the information contained in the data request.
Consider a situation in which a new transmission line was included in
Planning Assessment but cannot be built because right of ways cannot be
obtained. Should an upper limit be placed on planned load shed in such a
situation?
(2) We disagree with the threshold of 75 MW. In Order No. 762, the
Commission discussed the “blend concept,” where it “envisioned the
planner would consider up to 100 MW of planned Firm Demand
interruption along with other options to resolve the system performance

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Question 1 Comment
criteria violation and submit its documentation and explanation to the
entity deciding whether the planned load shed is acceptable.” (emphasis
added) Even the Commission envisioned using higher thresholds.
Furthermore, the data appears to show that one instance of NonConsequential Load Loss would be immediately out of compliance
because it is actual 75.2 MW not 75 MW. If the upper threshold is too
close to 75 MW, any load growth might also compel the instance to be
disqualified. If the SDT plans to keep the upper limit, we suggest
increasing the amount to at least 100 MW.

Response: (1) The SDT understands the problematic nature of future considerations in setting threshold values. However, the SDT
believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount of Load
planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No change made.
(2) The SDT believes that the threshold selected is consistent with the data supplied in the data request within reasonable limits.
Increasing the threshold to 100 MW is not consistent with the data supplied and the SDT believes that such an action would be
viewed as a non-acceptable least common denominator approach. No change made.
Minnkota Power Cooperative

No

Otter Tail Power Company

1. MPC QUESTION: If a portion of the non-consequential load loss used to
mitigate a contingency is controllable by a demand side load management
system, can it be excluded from the “Firm Demand interruption” in TPL002-1c Table I footnote ‘b’ and/or “Non-Consequential Load Loss” in TPL001-2a Table 1 footnote 12?
a. Would this load count towards the 25 MW and 75 MW thresholds?
b. Would it have to be curtailed on a pre-contingent basis in order to be
excluded from the non-consequential load total, or can it be excluded
even if the curtailment happens through action of the UVLS?
c. RECOMMENDATION: When describing “interruption of firm demand” or
“non-consequential load loss” in footnote ‘b’ add the language “not
counting load shed on a pre-contingent basis”. This would be added to the

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last sentence of footnote ‘b’ if it indeed should not be counted towards
the 75 MW threshold. Similar language could be added in Attachment 1
Section III in regards to the 25 MW and 75 MW thresholds and in TPL-0012a as well. This would explain much more clearly what is counted towards
the two thresholds and decrease confusion.
2. MPC QUESTION: If multiple companies own portions of the nonconsequential load loss used to mitigate a contingency at a single
substation, does each company’s load count towards the 25 MW and 75
MW thresholds or does the total load at the substation count?
a. EXAMPLE: 100% of the load at a substation is set to trip with automatic
UVLS. Company A, B, and C own load amounts X, Y, and Z at the
substation. i. Is the amount of load counted towards the 25 MW and 75
MW thresholds X+Y+Z, or is each counted separately?
b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I
footnote ‘b’ could read “In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed 75 MW from one entity.” Similar
language could be added in Attachment 1 Section III in regards to the 25
MW and 75 MW thresholds and in TPL-001-2a as well. This would explain
much more clearly what is counted towards the two thresholds and
decrease confusion.

Response: (1) Proposed TPL-002-1c states in the footnote that: “It is recognized that Firm Demand will be interrupted if it is: (1)
directly served by the Elements removed from service as a result of the Contingency, or (2) Interruptible Demand or Demand-Side
Management Load” (emphasis added). This makes it clear that Demand-Side Management Load is not to be considered as NonConsequential Load. In proposed TPL-001-2a, the proposed definition of Non-Consequential Load includes the term ‘Interruptible
Load’ which as defined in the NERC Glossary includes demand to be curtailed that the end-use customer makes available through
contract or agreement. Thus, the concept is covered in proposed TPL-001-2a as well. However, upon reviewing the comments, the
SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
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Question 1 Comment

Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
(2) “Ownership” of the Non-Consequential Load Loss is not a relevant factor; all thresholds mentioned in the footnote are related to
the total Non-Consequential Load Loss. No change made.
Iberdrola USA

No

“Contingency events” should be replaced by “Planning Events.”
Why would load shedding be limited only for certain circumstances in the
Near-Term Transmission Planning Horizon? The Near Term is likely the
period when the least can be done to avoid load shedding due to the time
required for permitting and construction of facilities.
A maximum capacity threshold is reasonable, whether 75 MW or a lower
value.

Response: The SDT agrees that ‘Contingency events’ should be replaced by ‘planning events’ in proposed TPL-001-2a where the
terminology in the performance tables uses ‘planning’ instead of ‘Contingency’. However, such a change is not warranted in proposed
TPL-002-1c where the ‘planning’ terminology was never used.
TPL-001-2a: footnote 12 - An objective of the planning process is to minimize the likelihood and magnitude of NonConsequential Load Loss following Contingency planning events.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. No change made.
Thank you for your support.
Massachusetts Attorney General

No

Although I voted for this Footnote, I do have concerns. 1) There is no
reliability benefit to the 75MVA threshold limit. There should be no limit
in the standard - it should be between stakeholders to decide that limit,
not nationally imposed.
2) Any such agreement to consider non-consequential losses should have
no impact to the BES especially when maintained in a confined boundary.

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3) This takes away local decision making of PUC/ Local Board decision
making;
4) FERC's concern that a few entities would disguise the "stakeholder"
process to shed load is unfounded and should not be applied on a
continent-wide basis. FERC is trying to impose tighter standards than
the industry wants.

Response: (1) The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap
on the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order.
No change made.
(2) The SDT agrees that it normally should not have an impact. However, the purpose of the footnote is to ensure that it will not
have an impact. No change made.
(3) The SDT disagrees. The PUC/Local Board would typically be part of the “applicable regulatory authorities or governing bodies
responsible for retail electric service issues” shown in Attachment 1, Section I, Bullet 1. The same body would be expected to be the
entity involved in Attachment 1, Section III. Therefore, the PUC/Local Board would be a primary participant in the proposed process.
No change made.
(4) The conditions placed on the stakeholder process will provide consistency in the application of footnote ‘b’ on a continent-wide
basis. No change made.
Xcel Energy

No

Although the maximum capacity value is used for planning purposes, how
does this correlate with operational standards/issues that may require
that value be greater. The planning studies look at very specific seasonal
conditions on the system and may not necessarily look at all the states of
the transmission system during the normal business day. If an operational
event requiring a greater value of Non-Consequential Load Loss (NCLL) is
executed and the specific outage was not considered in a planning study,
how will this affect compliance with the planning standard.
There was no technical rationale by the SDT for selecting the maximum
value, thus a limit should not be set and should be left as a general

Consideration of Comments: Project 2010-11

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discussion issue in the Stakeholder Process due to the many unforeseen
issues that may arise.

Response: The commenter correctly points out that this is a planning standard. Operational standards have their own sets of
requirements. The proposed requirements for TPL-001-2a state that models utilized must reflect System conditions anticipated for
the period in question. If the planner has done this, there should be no question as to whether they are fulfilling the requirements of
the standard. No change made.
The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount
of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. The limit selected
was derived from the data received for the data request. Use of actual data is the technical rationale in the selection of the
threshold. No change made.
Electric Reliability Council of Texas, Inc.

No

As an initial matter, ERCOT does not believe the planning process should
allow for nonconsequential load shedding under single contingency
conditions. Accordingly, ERCOT takes no position on the proposed
maximum load shedding amount.
Even though the NERC BoT approved the Stakeholder Process, ERCOT
does not believe that the Stakeholder Process should be included as an
Attachment to a footnote to a reliability standard.
Also, there is an inconsistency in the terminology used in the footnotes
relative to the load shed - firm demand and non-consequential load are
both used. Non-consequential load is the correct term and the language
should be consistent.
Although it is ERCOT’s position that non-consequential load should not be
allowed to be shed under single contingency conditions from a planning
perspective, if the SDT elects to retain a vehicle for such exceptions, it
should establish objective, reliability based criteria that lend themselves
to inclusion in a reliability standard. This is consistent with the general
approach for reliability standards, which prescribe the "what", not the

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"how". If the exceptions are based on objective criteria that are known
upfront, and those criteria reflect appropriate reliability based technical
justifications, then the risk of unwarranted exceptions to the general
prohibition due to misuse of the exception process is mitigated.
Furthermore, the exception process should be external to the NERC
Reliability Standards (e.g. in the Rules of Procedure), which should merely
reference authorized exceptions granted pursuant to that process.
With respect to the stakeholder process, in no case should a reliability
standard mandate a stakeholder process in any respect, procedural or
substantive. In ISO/RTO regions, stakeholder processes fall within
ISO/RTO governance matters. These issues are beyond the purview of
NERC Reliability Standards. In other regions, although the relevant
functional entities do not have stakeholder processes analogous to
ISOs/RTOs, any relevant processes are similarly beyond the scope of the
reliability standards.Accordingly, the SDT should eliminate all revisions
related to the establishment of a stakeholder process. As discussed in
response to question 5, FERC is not requiring this approach, but rather has
only provided guidance with respect to ways to possibly bring the prior
proposal in line with applicable regulatory approval standards for
reliability standards.
Additionally, as a general matter, substantive reliability standards
requirements should not be imbedded within a footnote to a
requirement. In this case, not only is there a substantive requirement
imbedded in the footnote, there is also a substantial attachment (which
must become part of the enforceable standard requirements}... and, to
make it worse, the attachment is an attachment to the footnote, rather
than an attachment to and referred to by a reliability standard
requirement.

Response: ERCOT is free to adopt a position of not allowing Non-Consequential Load shed in its reliability footprint. An entity can
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always do more than the requirements stated. No change made.
The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it
contained a stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria
for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail
and specificity to the already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in
Reliability Standards and both mechanisms have been used before. No change made.
The SDT believes that the terminology is consistent. Non-Consequential Load is a newly defined term that only applies to proposed
TPL-001-2a. It is not appropriate to use this terminology in proposed TPL-002-1c which predates proposed TPL-001-2a. No change
made.
The SDT has set up criteria for consideration in the potential usage of footnote ‘b’ for planning purposes in Attachment 1, Section II,
Bullets 1 through 8. The criteria described are objective. The process describes what must be done to allow for the usage of footnote
‘b’ in the planning process. No change made.
The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it
contained a stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria
for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail
and specificity to the already approved approach. If the ISO/RTO has an existing process that meets the requirements, it is free to
use such process as stated in Attachment 1, Section I. No change made.
Footnotes and attachments are acceptable mechanisms for use in Reliability Standards and both mechanisms have been used before.
No change made.
National Association of Regulatory Utility
Commissioners

No

Consideration of Comments: Project 2010-11

As NARUC stated plainly in its Comments filed in FERC Docket No. RM1118 (Dec. 20, 2011), “not only does the law require that the States maintain
authority over distribution level reliability, States are in the best position
to guide load shedding so that it has the least negative impact on the
State’s customers and the operation of the local distribution system.” Id
at p. 4. Given the twin responsibilities of FERC to maintain bulk system
reliability and the states to ensure reliable and affordable service to retail
load, NARUC supports the portion of the standard that requires
notification and consultation with state and local regulators. However,
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Question 1 Comment
the maximum capacity threshold (set at 75 MW) is problematic. In this
instance, it appears that the 75 MW maximum capacity threshold is
merely a reflection of antidotal information from five data request
responders and as such is not technically justified. NARUC is not poised to
offer an alternative; given that the state/local regulator is consulted in
this process, the maximum capacity threshold should just be dropped.
States should be able to authorize an 80 MW exception, or whatever level
is reasonable, under specific circumstances if local economics and
reliability warrant it.

Response: The data request is not anecdotal information. All of the Transmission Planners in the continental United States supplied
their data in response to the data request. The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the
planning process without a cap on the amount of Load planned to be shed. The SDT also believes that such a position is consistent
with the wording in the Order. Given the participation of appropriate regulatory bodies in both Sections I and III, the SDT believes
that the current threshold is the best possible solution. No change made.
American Transmission Company

No

ATC recommends the following alternative language for both Footnote ‘b’
(Table 1 in TPL-002-1c [page 6]) and Footnote ‘12’ (Table 1 in TPL-001-2a
[page 14]:(1) Change the wording at the end of the first sentence from
“following Contingency events” to “following Contingency events for the
prior condition of all equipment in service or during the planned
(maintenance) outage of any bulk electric system equipment”. This would
remind Transmission Planners and Planning Coordinators to include the
consideration of planned outages at demand levels for which the outage
would be performed.
(2) In the last sentence of the footnote, raise the maximum load dropping
threshold for the footnote from 75 MW to 100 MW. A 100 MW threshold
is reasonable because the DOE uses the intentional dropping of more than
100 MW as one of the thresholds for determining when enough load is
dropped to justify a formal system event analysis.

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Question 1 Comment
(3) Add a sentence at the end of the footnote to read, “This footnote
does not apply to any load that is not NERC registered (e.g. load that does
not meet the greater than 25 MW NERC registration criterion).

Response: (1) Consideration of planned outages at demand levels for which the outage is performed is covered in proposed TPL-0012a, Requirement R1 where it is stated that models must represent actual System conditions as well as in Requirement R2, Part 2.1.3
which states that analysis is to be done when known outages are scheduled. No change made.
(2) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a least common denominator approach and would thus be rejected. No
change made.
(3) Load that is served from the entity’s transmission system is considered as applicable Load in this standard regardless of the
underlying registration situation. No change made.
Hydro Québec TransÉnergie

No

Dropping load in the general sense should not be endorsed, but it is
recognized that there are special situations where it cannot be avoided.
Provided there is no widespread, adverse effect on the reliability of the
interconnected BES, the effect of a firm demand interruption on
customers is under the purview of the applicable regulatory authority that
is responsible for local transmission and retail service over the load to be
curtailed, and the TPL standard should not put a limit at 75 MW.

Manitoba Hydro

No

Given that it is deemed that a stakeholder procress is required, there is no
rationale for a maximum level. The stakeholders are in the best position
to judge the appropriate level of allowable curtailment.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No

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change made.
Florida Municipal Power Agency

No

Lakeland Electric
Gainesville Regional Utilities

FMPA has two issues:1. What is the technical justification for 75 MW?
There is no other metric in use similar to it. FMPA believes that, if the
stakeholder process reveals that the stakeholders are willing to accept
decreased service continuity to save money on their electric bills, why
should that be limited to 75 MW which has nothing to do with BES
reliability. BES reliability will not be impacted until load shedding gets
near to the largest single loss of source contingency in relation to supply /
demand mismatch. Other standards have chosen the low value of 300
MW as indicative, (e.g., CIP v5 for UFLS, EOP-004 for disturbance
reporting); hence, FMPA recommends that the maximum amount of load
shedding be 300 MW.
2. The footnote should also address a process whereby the transmission
customer agrees to conditional firm service if the Transmission Planner /
Transmission Service Provider (TSP) plans on curtailing firm service to that
customer following a single contingency. The TSP should not be able to
unilaterally degrade service from a state where it was not conditional to a
state where it is conditional.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. The
remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’ by
planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount of
Load that could be planned to be shed under footnote ‘b’. Other thresholds can be a point of reference or sanity check but in and of
themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the threshold derived
from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
An entity can always approach a customer to request to a change in the type of service provided, with or without the consideration
of footnote ‘b’ utilization. The institution of the formal process proposed here would bring the transmission customer into the
decision making process which makes any condition open and transparent and which may initiate discussions on service type as
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referenced above. No change made.
Modesto Irrigation District

No

I am voting NO because there is no technical basis for use of the 75 and
25 MW absolute threshold values, regardless of the size of the utility's
load, referenced in the proposed standard. WECC's past experience with
implementation of arbitrary magnitudes for requirements (e.g., the 5%
and 7% arbitrary magnitude contingency reserve requirements), has
proved to be problematic. I would suggest investigating a technical basis
for using a relative requirement, such as percentage of the utility's load,
maybe 5% and 2.5%, respectively, and that it be based on technical
requirements similar to those found in Table 1 of the WECC Criteria TPL001-WECC-CRT-2.Thank you.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Utilizing a percentage of an entity’s Load may be
problematic – when dealing with a small entity it could be a small value but still of rather large import and if dealing with a large
entity could result in significant amounts of Load shed being planned. The FERC Order states that a percentage approach would not
be appropriate for the aforementioned reasons. The SDT believes that any deviation from the threshold derived from the actual data
may be viewed as a non-acceptable least common denominator approach. No change made.
Ameren

No

Consideration of Comments: Project 2010-11

It appears that a least common denominator approach was used to
develop the upper limit of 75 MW. Only 1 out of 18 respondents would
drop 75 MW of load, and only two respondents would drop 61-70 MW of
load. Our review of the data request responses concludes that only 22%
of the respondents that presently utilize footnote “b” would drop more
than 50 MW, and only 33% of the respondents that use footnote “b”
would drop more than 40 MW. The proposed 75 MW limit is too high and
is not supported by the responses to the data request. An upper limit of
40 MW is more appropriate, based on the data responses.

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Response: Based on the comments received, the majority of the industry does not agree that a lower threshold would be
appropriate. The SDT does not believe that a least common denominator approach was utilized. The value selected is a reasonable
limit based on the data received, potential vagaries in future considerations, and undefined system configurations that may arise. No
change made.
MidAmerican Energy Company

No

MidAmerican supports NSRF comments with one change. The proposed
NSRF addition of “consideration of planned outages at demand levels for
which the outage would be performed” to the text of footnote “b” after
“following Contingency events” should not be added. If the addition is
made, a reasonable time frame clarification is necessary and should be
added such as “greater than 6 months”. The proposed change would then
read “consideration of planned outages greater than 6 months or longer
at demand levels for which the outage would be performed”.

Response: The SDT is not proposing to adopt the suggested change of the MRO NSRF. Please see the response to MRO NSRF above.
Midwest Independent Transmission System
Operator, Inc.

No

No. We believe footnote b in NERC TPL 002-1 and/or footnote 12 in TPL001-2 should be eliminated because the intent of these standards is not to
rely on non-consequential firm load shedding after a single contingency
event. However, if these footnotes are not eliminated, there should be
some limitation on how much firm load shed is allowed. We object to any
level higher than the proposed 75 MW level and would prefer a level
below 75 MW, but won’t object to the proposed 75 MW level if the
footnotes are not eliminated.

Response: The SDT believes that the wording of the footnote states that Non-Consequential Load shedding should not be the intent
but recognizes that particular circumstances may result in such a planned action. The 75 MW level is being retained. No change
made.
Duke Energy

No

Consideration of Comments: Project 2010-11

Regarding the maximum capacity item, we believe that 75 MW is much
too low. While Duke Energy has not historically used the footnote, setting
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the upper limit at 75 MW raises a concern. An upper limit of 75 MW
severely limits the ability of a Transmission Planner to use the footnote.
The 75 MW limit appears to be the maximum reported in the survey. The
survey is a snapshot in time and to assume that there never have been
nor never will be situations where the correct decision of a Transmission
Planner and its stakeholders would be to exceed the 75 MW limit is
illogical. The 75 MW limit is likely to create a situation where a
Transmission Planner is forced to convert a network line to radial in order
to remain in compliance with the standard, to the detriment of reliability
to customers. The key to understanding use of the footnote is realizing
that, in most cases, using the footnote is extremely unlikely to result in
customer outages, because the probablility of the initiating contingency
occurring under conditions requiring additional load shed is very low. A
more reasonable upper limit would be the 300 MW limit that is
established as the threshold for DOE Disturbance Reporting. It is also
important to remember that no matter what upper limit is established,
Non-consequential Load Loss of 25 MW or greater cannot be included in
Year One of the Planning Assessment if the applicable regulatory authority
or governing body responsible for retail electric service issues objects.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southern California Edison Company

No

Consideration of Comments: Project 2010-11

SCE believes that the maximum capacity threshold should be increased
from 75 MW to 250 MW, as 250 MW is the limit utilized by the California
Independent System Operator (CAISO) for a consequential load drop for a
single contingency. The CAISO has a rigorous transmission planning

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Question 1 Comment
process that allows it to plan for and permit load shedding up to 250 MW.

Response: The footnote only applies to Non-Consequential Load Loss. Upon reviewing the comments, the SDT has seen that
Demand that is not included as Firm Demand for footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Arizona Public Service Company

No

The 75 MW threshold is too low. No technical justification has been given
for choosing 75 MW. It should be a significantly higher value for TPL-002.
Currently AZPS does not use non-consequential load dropping to meet
any standard but this option should be preserved. There could be times
when alternate to the load dropping would be building a new
transmission line costing hundreds of millions of dollar for a very low
probability scenario of high load conditions. The threshold value should
be 100 MW or more.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Northeast Power Coordinating Council

No

Consideration of Comments: Project 2010-11

The 75MW of Firm Demand interruption is retail load that is being
dropped. Dropping load in the general sense should not be endorsed, but
it is recogn ized that there are special situations where it cannot be
avoided. If a regulator responsible for retail load is comfortable with
greater than 75MW being dropped in a rare situation, there should not be
a requirement to build out of the situation. Provided there is no
widespread, adverse effect on the reliability of the interconnected BES,
the effect of a firm demand interruption on customers is under the
purview of the applicable regulatory authority that is responsible for local
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Question 1 Comment
transmission and retail service over the load to be curtailed.
There is no technical basis for the 75MW figure. It was included as a
result of a Section 1600 Data Request, and is an arbitrary value. There
should not be a limit without a technically supportable reliability based
reason.

National Grid

No

The 75MW of Firm Demand interruption is retail load that is being
dropped. Dropping load in the general sense should not be endorsed, but
it is recognized that there are special situations where it cannot be
avoided. If a regulator responsible for retail load is comfortable with
greater than 75MW being dropped in a rare situation, there should not be
a requirement to build out of the situation. Provided there is no
widespread, adverse effect on the reliability of the interconnected BES,
the effect of a firm demand interruption on customers is under the
purview of the applicable regulatory authority that is responsible for local
transmission and retail service over the load to be curtailed.
There is no technical basis for the 75 MW figure with respect to reliability
impact. Although, the value was developed by the SDT as a result of their
review of Section 1600 Data Request, there was no reliability based
analysis performed to identify whether the 75 MW is reasonable number.
It is possible that a number either larger or lower could be identified if a
reliability and cost-effective analysis is conducted.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No
change made.
The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’
by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount
of Load that could be planned to be shed under footnote ‘b’. All of the Transmission Planners in the continental United States
supplied their data in response to the data request. The SDT believes that any deviation from the threshold derived from the actual
Consideration of Comments: Project 2010-11

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Question 1 Comment

data may be viewed as a non-acceptable least common denominator approach. No change made.
ISO New England

No

The draft footnote states that interruption “is limited to circumstances
where the Non-Consequential Load Loss meets the conditions shown in
Attachment 1.” Attachment 1 appears to impermissibly require State
participation in federal transmission planning processes. Further, it places
the ERO in a Transmission Planning role, which exceeds the limits of the
ERO’s functions under Section 215 of the Federal Power Act. The current
language appears to conflict with (1) federal statutes that are clear that
wholesale electric transmission issues are matters of federal, and not
state, jurisdiction, (2) orders of the Federal Energy Regulatory Commission
(“FERC”) regarding the role and independence Regional Transmission
Organizations (“RTOs”) with regard to transmission planning, and (3)
Section 215 which limits NERC’s authority to regulate “users, owners and
operators” of the Bulk-Electric System. Further, the conditions appear to
conflict with Section 215 of the Federal Power Act by placing the ERO in a
transmission planning role and providing it with regulatory or functional
oversight regarding the substance of transmission planning decisions. The
ERO has the authority to develop and enforce standards, but is not a
transmission planning entity and does not have the authority to substitute
its judgment for registered Planning Authorities and Transmission
Planners regarding the planning or operation of the bulk power system.
Where a review is sought of planning entities’ determinations, per FERCfiled Tariffs, they may be brought before FERC under Section 206 of the
Federal Power Act. Because the footnote, and the associated Attachment
appear to be in conflict with FERC Tariff and other statutory provisions,
they should be removed.
The footnote itself states, “An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency events.” The objective statement within the

Consideration of Comments: Project 2010-11

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Question 1 Comment
standard does not appear to create a requirement and should be
removed.

Response: The SDT does not believe that the footnote violates any regulations concerning transmission planning since there is no
federal process as cited in the comment. The proposed process simply brings stakeholders, including local regulators, to the table in
an open and transparent manner while setting criteria for when footnote ‘b’ can potentially be utilized. The ERO is not participating
in the planning process. The role of the ERO is restricted to a determination of whether the planned utilization of footnote ‘b’ will
cause an Adverse Reliability Impact to the BES. The ERO has no further role in the transmission planning process beyond that
determination. No change made.
The SDT believes that the objective statement referenced is an important consideration in the over-all planning process and thus
should be retained. It sets the over-all tone and approach that should be followed. No change made.
Deseret Generation & Transmission

No

The limitation of Non-Consequential load loss to the 25 MW-75 MW level
with a hard limit at 75 MW is arbitrary and give no deference to the cost
of the cure. In the West the high cost of a fix may not be in the public
interest. The 75 MW hard high limit should be replaced with a soft 75
MW limit but allowing higher levels if the governing body or regulatory
authority approves it.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes it is
unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a hard cap on the amount of Load planned
to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No change made.
New England States Committee on
Electricity (NESCOE)

No

Consideration of Comments: Project 2010-11

The New England States Committee on Electricity (NESCOE) appreciates
the opportunity to comment on NERC’s proposed revisions to
Transmission Planning (TPL) Reliability Standards relating to permissible
applications of planned load interruption. NESCOE is New England’s
Regional State Committee and is governed by a board appointed by the
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Question 1 Comment
six New England Governors. These comments reflect the collective view
of the six New England states.The issue of planned, limited load
interruption rests at the central intersection of cost and reliability. It
illustrates the fundamental balance that Commissioner Norris details in
Order No. 762: the tradeoffs between “increasing levels of reliability and
the costs that come along with achieving them.” Transmission Planning
Reliability Standards, Order No. 762, 139 FERC ¶ 61,060 (April 19, 2012)
(Norris, Comm’r. concurring in part and dissenting in part) at 2. NESCOE
agrees with Commissioner Norris that, as a general matter, this balancing
should translate to a more explicit consideration of costs in the NERC
standard development process. Id. at 1. The language in footnote “b”and corresponding footnote 12 of TPL-001-2-implicitly recognizes cost
considerations in transmission planning by tolerating limited load
shedding under defined circumstances. NESCOE offers below comments
and suggestions in response to the SDT’s questions. These responses
reflect NESCOE’s interest in planning for a robust bulk electric system
while taking into account the magnitude of risk that a solution is intended
to address and the costs associated with competing solutions.
NESCOE appreciates the work of the SDT in attempting to respond to the
Commission’s directives and the time constraints under which the SDT
was required to make changes to footnote “b.” However, NESCOE is
concerned that establishing a bright-line maximum capacity threshold
that is an absolute ceiling is overly prescriptive and unnecessary to meet
the Commission’s directives. In Order 762, the Commission rejected the
contention that regional stakeholder processes should unilaterally
determine the appropriate criteria to apply in planning to interrupt firm
load. Order 762 at P 32. However, provided that technical parameters
are in place, the Commission stated that it would be “amenable” to
regional stakeholders establishing such criteria if, for example, NERC or
the applicable Regional Entity “developed an exception process that

Consideration of Comments: Project 2010-11

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Question 1 Comment
provides flexibility in decisions based” on their expert view of regional
considerations. Id. The SDT’s proposal, however, would impose a onesize-fits-all requirement that forecloses a regional discussion of the
quantitative and qualitative considerations that may justify an exception
to the proposed 75 MW maximum capacity value. Such a regional
discussion in ongoing in New England. In 2010, ISO New England
introduced to stakeholders a draft Transmission Planning Load
Interruption Guideline. The Guideline noted that load interruption should
not be the principal tool to address transmission system reliability
violations and highlighted the priority of reliable service. However,
applying quantitative and qualitative criteria, the Guideline proposed for
stakeholder discussion various levels of controlled load interruption in N1-1 conditions-potentially up to hundreds of megawatts-that may be
tolerated under clearly defined conditions. NESCOE did not take a view of
the Guideline when it was presented for review and does not do so here.
For now, the Guideline remains in draft form following stakeholder
comment in 2011. However, imposition of a maximum capacity threshold
that is an absolute ceiling for N-1 events and potentially, through revisions
to footnote 12, N-1-1 events, would prematurely limit important regional
discussions of this issue. A better approach, and one which the
Commission appears amenable, would be to accompany any bright-line
value with an exception process. There is recent precedent supporting
such an approach: NERC proposed changes to its Rules of Procedure to
accommodate exceptions to the proposed 100 kV bright-line Bulk Electric
System definition.
Separately, the footnote references Attachment 1 to the respective
planning standards, which requires a stakeholder process review of the
utilization of planned interruption. Such review is only triggered if
utilization is sought in the Near-Term Transmission Planning Horizon, even
though the footnote permits utilization of load interruption throughout

Consideration of Comments: Project 2010-11

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Question 1 Comment
the planning horizon. NESCOE does not support this limiting language,
which is at tension with an open and transparent planning process over
the entire planning horizon. The term “Near-Term” should be stricken or
further justification should be provided.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes it is
unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the amount of Load planned to be
shed. The SDT also believes that such a position is consistent with the wording in the Order. The SDT believes that the referenced
exception process is what is being proposed. The proposed process sets up an open and transparent process for allowing such Load
shed in specific conditions and with specific limitations. Any future revisions to footnote 12 will be accomplished through the
approved standards development process and any discussion on changing threshold values would be part of that process. No change
made.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as mandatory for the
Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but does not limit its
use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission Planning Horizon
situations in its individual stakeholder processes is left to the entity to determine. No change made.
Sacramento Municipal Utility District

No

There is no reliability benefit with an establish MW threshold.
Implementing any threshold is descriptive and the standard should depict
an outcome not the means of the outcome.

Response: The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on
the amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. No
change made.
Public Utility District No.1 of Snohomish

No

Consideration of Comments: Project 2010-11

We believe the survey significantly underestimated the use of NonConsequential Load Shedding because the survey asked about past usage
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Yes or No

County
Tacoma Power
MEAG Power
City of Austin
Clark Public Utilities

Question 1 Comment
of footnote b under Version 001, not about planned load shedding in TPL
version 002 or the proposed footnote 12. TPL version 002 added several
new contingencies, and also changed the Non Consequential Load
shedding applicability for several contingencies.
We have 4 specific concerns, followed by several suggested edits: 1)
Analyzing the contingencies “P1.4 Loss of a Shunt Device” and “P2.1
Opening of a line section w/o a fault” are new requirements that will lead
to increased use of footnote 12. It is common on fringes of the
interconnected system to have weak sources. Significant utility
investment will be redirected to remediate these fringe performance
issues due to the P2.1 and its associated restrictions for firm load
shedding and no RAS or UVLS mitigation. This is a low probability and low
impact to the main grid contingency with a high mitigation cost, given the
new mitigation restrictions.
2) Contingencies “P2.2 Bus Section fault” and “P2.3 Internal Breaker
Fault” were previously defined as category “C multiple contingencies”
with the restriction that the Firm Load shedding must be
planned/controlled. However Version 002 no longer allows dropping
nonconsequential load for EHV but removes all restrictions for HV load
shedding. Since these contingencies result in opening the same breakers
as category P1 contingencies, the use of footnote 12 should be consistent
with P1.
3) Contingencies P3.1-P3.4 were previously defined as category “C
multiple contingencies” with Firm loading shedding allowed. In version 2,
these contingencies have been changed from allowing planned load
shedding to only allowing Non-Consequential load shedding per footnote
12. Although this does not directly impact our utility, the survey results
do not include utilities using “must-run” generation.
4) As demonstrated by multiple questions at the last webinar, many

Consideration of Comments: Project 2010-11

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Question 1 Comment
utilities do not understand the definition of Non-Consequential Loads, and
therefore may not have correctly reported the usage of NonConsequential Load Shedding. The v2 changes cascade to the unfortunate
conclusion that UVLS and RAS are no longer permitted as cost effective
transmission performance mitigation, despite new low probability
contingencies that drive performance problems at the edges of the
network.
-Proposed changes: A) Change the maximum amount from 75 MW to 300
MW. Several other standards including CIP have a strong technical basis
for selecting 300 MW as the maximum limit for load shedding programs.
B) Footnote 12 on contingency 2.1 should be replaced with a new
footnote 15 that reads “ 15. For this contingency, load which is served
radial from a remaining single source line may be shed as if it were
Consequential Load.” This change would acknowledge that while P2.1
does involve just one element, the likelihood of occurrence is similar to
bus section faults, so the resulting system performance requirements
should be similar.
C) The first two sentences of footnote 12 should be deleted. Remove the
first sentence because it is general in nature and is a basic tenant of any
load-serving utility. Remove the second sentence because column 7 of
Table 1 explicitly states where Non-Consequential Load Loss is allowed.
D) The third sentence of footnote 12 should have the words “under
footnote 12” added. Without this addition, all Non Consequential Load
Loss including the allowed loss for P4, P5 and P6 would still be subject to
Appendix 1. The revised sentence would read “When Non-Consequential
Load Loss is used under footnote 12 within the Near-Term ...”

Response: The SDT could not reasonably request data for unknown future conditions. The only viable mechanism for data input was
the data request as it was formulated.
Consideration of Comments: Project 2010-11

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Yes or No

Question 1 Comment

1) The SDT disagrees that planning events P1.4 and P2.1 are ‘new’ requirements in proposed TPL-001-2a. These requirements were
previously approved by the industry and NERC Board of Trustees. No change made.
2) The SDT disagrees that P2.2 and P2.3 planning events will open the same breakers as P1 planning events. For the EHV planning
events cited, the standard approved by the industry and the NERC Board of Trustees accepted a raising of the bar by not allowing
Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the application of the
footnote. No change made.
3) For the P3.1 – P3.4 planning events, the standard approved by the industry and the NERC Board of Trustees accepted a raising of
the bar by not allowing Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the
application of the footnote. No change made.
4) Discussion of the proposed definition of Non-Consequential Load was provided during the various postings of proposed TPL-0012. The SDT has received no comments from other utilities regarding confusion over the definition. Single Contingencies are not
low probability events. No change made.
A) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value
for the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as the 300 MW referenced
above can be a point of reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter.
The SDT believes that any deviation from the threshold derived from the actual data may be viewed as a non-acceptable least
common denominator approach. No change made.
B) For planning event P2.1, the standard approved by the industry and the NERC Board of Trustees accepted a raising of the bar by
not allowing Non-Consequential Load Loss for these events. This posting of proposed TPL-001-2a does not change the application
of the footnote. No change made.
C) The SDT believes that such statements are important to set the tone and approach to be taken with the planning standards. No
change made.
D) The SDT agrees and has made the suggested clarification.
TPL-001-2a: footnote 12 - 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.
Independent Electricity System Operator

No

Consideration of Comments: Project 2010-11

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
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Question 1 Comment
no adverse effect on the reliability of the interconnected bulk power
system, the effect on customers of a firm demand interruption is the
responsibility of the applicable regulatory authority or its agencies
responsible for local transmission and retail service over the load to be
curtailed.We propose replacing the sentence, in the footnote and in
attachment one, section III that reads:”In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is
a Canadian Entity (or a Mexican Entity) should be implemented in a
manner that is consistent with/or under the direction of the Applicable
Governmental Authority or its agency in Canada (or Mexico).

Hydro One Networks Inc.

No

Consideration of Comments: Project 2010-11

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected bulk
electric system, the effect on customers of a firm demand interruption is
the responsibility of the applicable regulatory authority or its delegated
agencies responsible for local transmission and retail service over the load
to be curtailed.If it is decided to proceed with the 75 MW or any other
value, we propose replacing the sentence, in the footnote and in
attachment one, section III that reads:”In no case can the planned NonConsequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a non-US Registered Entity
should be determined by the applicable Regulatory Authority or
Governmental Authority or its delegated agency in that is responsible for
retail electric service issues in that jurisdiction.”

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Question 1 Comment

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
NB Power Transmission

No

We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected bulk
electric system, the effect on customers of a firm demand interruption is
the responsibility of the applicable regulatory authority or its delegated
agencies responsible for local transmission and retail service over the load
to be curtailed.

NBSO

No

We do not agree with setting a MW limit for non-consequential load loss.
The allowable amount should be determined and approved by the
jurisdiction of the area(s) whose load is affected. The intent of the TPL
standard and this footnote is to ensure that if non-sequential load loss is
accounted for or relied up to ensure BES reliability (as assessed in the
planning horizon), that such a decision needs to be approved by the
appropriate jurisdiction. Non-consequential load loss being applied or
considered to achieve BES reliability in planning assessment is in itself not
a BES reliability concern that rises up to a continent-wide reliability
standard.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as 300 MW can be a point of reference
or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation
from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No
change made.

Consideration of Comments: Project 2010-11

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Yes or No

Western Area Power Administration

No

Question 1 Comment
We do not support a maximum threshold of 75 MW or any MW level. It is
not appropriate to enforce a one size fits all maximum value. There are
no apparent reliability benefits from implementing a capacity loss
limitation...why not pick 300 MW?
Also we are not sure what prompted the additional distinction of allowing
the load shedding only in the near-term planning horizon...please
elaborate.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds such as 300 MW can be a point of
reference or sanity check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any
deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach.
No change made.
Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can be
interrupted throughout the entire planning horizon. No change made.
Platte River Power Authority

No

We do not support a maximum threshold. 1) It is not appropriate to
enforce a one size fits all maximum value that might unnecessarily overburden some communities.
2) The public process proposed in this standard provides significant
transparency from the transmission utilities and opportunity for
community input to decisions that will impact both the community's
reliability and rates.
3) Leave the maximum capacity threshold decisions to local regulatory
commissions and Boards of Directors.

Response: (1) The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage
of footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value
Consideration of Comments: Project 2010-11

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Yes or No

Question 1 Comment

for the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
(2) Thank you for your support.
(3) The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the planning process without a cap on the
amount of Load planned to be shed. The SDT also believes that such a position is consistent with the wording in the Order. Local
regulators are involved in the process through the wording in Attachment 1, Sections I and III. No change made.
California Independent System Operator

No

While we have voted in favor of supporting the changes to the footnote
and to move forward with the adoption of the standard, we remain
concerned that there is not a good foundation for concluding that loss of
load over 75 MW poses a reliability risk to the system compared to some
higher MW threshold. Instead, the 75 MW capacity threshold is simply
based on the current maximum planned loss of Non-Consequential Load.
While we support minimizing reliance on Non-Consequential Load Loss,
there may be scenarios where such reliance is unavoidable in the nearterm, and therefore may be needed until capital upgrades can be put in
place. At a minimum, the footnote or standard should provide for an
exception process, should it be necessary for a planned NonConsequential Load Loss of greater than 75 MW.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. The SDT believes that the
referenced exception process is what is being proposed. The proposed process sets up an open and transparent process for allowing
such Load shed in specific conditions and with specific limitations. No change made.
Tri-State Generation & Transmission
Association

No

Consideration of Comments: Project 2010-11

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Yes or No

LCRA Transmission Service Corporation

No

Question 1 Comment

Response: Without a specific comment, the SDT is unable to respond.
TVA Transmission Reliability Engineering
and Controls

Yes

TVA agrees with the general text; however, TVA believes that the 75 MW
limit is too low. TVA believes that a better limit would be 100 MW - which
is the amount for load shedding required to be reported under OE-417
under emergency operational policy. This would allow some future load
growth as well as any possible new loads that may develop quickly in
which a utility may not have time to complete necessary projects in a
corrective action plan.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. DOE thresholds can be a point of reference or sanity check
but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southwest Power Pool Reliability Standards
Development Team

Yes

Bonneville Power Administration

Yes

SERC EC Planning Standards Subcommittee

Yes

Associated Electric Cooperative, Inc.
Southern Company

Yes

American Electric Power

Yes

Seminole Electric Cooperative, Inc.

Yes

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Public Service Company of New Mexico

Yes

Idaho Power Company

Yes

SCE&G

Yes

Lincoln Electric System

Yes

Georgia Transmission Corp

Yes

Question 1 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11

45

2.

Do you agree with the description and components of the Stakeholder Process in Section I of Attachment 1? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: There was little or no commonality in the comments submitted and the responses are mainly statements
clarifying SDT intent as shown in the individual responses.
The following change was made due to industry comment:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Organization

Yes or No

Southern Company

No

The complex stakeholder process described in Attachment 1 should be required
only if the amount of planned load shed exceeds 25 MW or the contingency is
greater than 300 kV. Since the average use given in the survey was 19 MW and
there is no evidence of harm to the BES reliability resulting from that use, there is no
good reason to require such a stakeholder process for amounts less than 25 MW.
The stakeholder process should only be required for larger amounts of load.

SCE&G

No

No, We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

TVA Transmission Reliability
Engineering and Controls

No

TVA recommends that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting

Consideration of Comments: Project 2010-11

Question 2 Comment

46

Organization

Yes or No

Question 2 Comment
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

SERC EC Planning Standards
Subcommittee

No

Associated Electric Cooperative

We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. Since the average use given in the
survey was 19 MW and there is no evidence of harm to the BES reliability resulting
from that use, there is no reason to require a stakeholder process for amounts less
than 25 MW. This is consistent with the value cited in Section III.

Response: The SDT disagrees that the proposed process is complex or unnecessary. The SDT used the Board of Trustees approved
standard as a starting point for this draft. FERC remanded the standard; not because it contained a stakeholder process, but because
the process was not well defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and
did not assure that BES reliability would be maintained. The balloted draft added detail and specificity to the already approved
approach. The SDT believes that all uses of footnote ‘b’ should go through the stakeholder process. No change made.
Seminole Electric Cooperative,
Inc.

No

#1.It is unclear what factors must be met in order to be an affected stakeholder
under the Stakeholder Process in Attachment 1? This process appears to be devoid
of any objective factors that can assist an entity in determining whether a party is a
stakeholder or not. NERC should define what an “affected stakeholder” is or list
factors to assist industry in making such a determination.
#2.In Standard TPL-002-1c, Attachment 1, Section I. “Stakeholder Process,” there
was a section added at the end of this subsection that is three lines in length. This
section states that a stakeholder process does not need to be repeated unless there
has been a “material change.” It is clear from the latest webinar presentation on
this Project that this language is not “clear and unambiguous”. NERC does not
present any metrics, whether qualitative or quantitative, to guide industry as to
when a material change occurs to an application of footnote ‘b.’ Without any
metrics to guide industry, it is bewildering that NERC reasons that entities will
consistently interpret what a material change constitutes. Therefore, SECI believes
that this provision is in conflict with the NERC Rules of Procedure and FERC Order

Consideration of Comments: Project 2010-11

47

Organization

Yes or No

Question 2 Comment
762.
#3.In Standard TPL-002-1c, Attachment 1, Section I. “Stakeholder Process,” the
requirement that the process “shall be documented” was deleted from the first
paragraph. It does not appear to be reasonable that a process that is not written,
nor known to any stakeholder, meets the common understanding of “open and
transparent.” Seminole believes that the requirement that the process be
documented and that documents be available to potential affected parties be
reinstated into the Standard.

Response: 1. The SDT believes that the planning entity is in the best position to identify affected stakeholders and that any attempt
to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a one size
fits all approach. No change made.
2. The SDT believes that the planning entity has the best understanding of when a change would become material. With the large
range of design philosophies and geographic difference between the entities within NERC, it is not practical to adopt a single one size
fits all approach. In addition, since the use of footnote ‘b’ will be a part of the entity’s Corrective Action Plans, interested
stakeholders will have the opportunity to question the continued use of footnote ‘b’. No change made.
3. The SDT believes the ‘documented’ terminology is unnecessarily redundant since the entity must be able to demonstrate
compliance to its Compliance Enforcement Authority. It should not be necessary to mandate that an entity has to document a
process. No change made.
NBSO

No

(1) The process presented in Section I of Attachment I is overly prescriptive. This
Section needs only to stipulate that the proposed utilization of the footnote be
reviewed through an open and transparent stakeholder process developed and/or
approved by the jurisdiction (a Regional Entity or regulatory authority) of the area(s)
whose load is affected area.
(2) There is no basis to support allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment only. The footnote
itself should not explicitly restrict its utilization to only the Near-Term horizon.
Often, in the long-term planning horizon, when approval for transmission addition

Consideration of Comments: Project 2010-11

48

Organization

Yes or No

Question 2 Comment
or reinforcement cannot be obtained for whatever reasons, utilization of the
footnote is considered and adopted, subject to stakeholder’s and regulatory
authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year 0ne) time frame and hence the proposed
provision does not allow for utilizing the footnote for the interim period before new
or reinforced transmission facilities are put in place. We suggest removing the word
“Near-Term”.

Response: (1) FERC remanded the standard because they wanted the stakeholder process better defined, including a blend of
quantitative and qualitative criteria for allowing curtailment of Firm Demand and assurance that BES reliability would be maintained.
The balloted draft added the indicated detail and specificity to the already approved approach. No change made.
(2) Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm Demand can
be interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as mandatory for
the Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but does not limit
its use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission Planning Horizon
situations in its individual stakeholder process is left to the entity to determine. No change made.
ACES Power Marketing Standards No
Collaborators

(1) Many RTOs have well organized stakeholder processes that could be utilized to
satisfy Attachment 1. Because the TPL standards apply to both the PC and TP, one
may conclude that both functions need to have a stakeholder process. Rather, we
think that the TP should be able to rely on its PC’s stakeholder process. We
recommend clarifying Attachment 1 that it is acceptable for the TP to rely on the
PC’s process and that both entities are not required to have redundant processes.
The most important point is that stakeholders have an opportunity to participate.

Response: The SDT believes that it has covered this possibility in the revised language posted for this draft allowing an entity to use
an existing process as long as it meets the criteria. Such usage is not restricted to a particular entity and as long as each entity is able
to demonstrate that it meets the items in Section I, entities can share the same process. No change made.
Minnkota Power Cooperative

No

Consideration of Comments: Project 2010-11

1. MPC QUESTION: In Attachment 1 Section I, what is the definition of a

49

Organization

Yes or No

Otter Tail Power Company

Question 2 Comment
“stakeholder”?
a. Is this intended to apply to multiple NERC functional entities (DP, TO, TOP, LSE),
public residential customers, and/or business owners that are affected by system
contingencies?
b. RECOMMENDATION: Define stakeholder to be “affected Transmission Owners,
Transmission Operators, Distribution Providers, and Load-Serving Entities.” We
believe it is most appropriate for the Transmission Owners, Transmission Operators,
Distribution Providers, and Load-Serving Entities to objectively evaluate the risks of
load shedding in a local area against the cost impact of a large transmission project
on the rate base.
2. MPC QUESTION: In Attachment 1 Section I item 1, what does “including
applicable regulatory authorities” refer to?
a. Is this the same body that “applicable regulatory authority or governing body”
refers to in Section III?
b. Are these requirements still applicable if the 25 MW threshold in Section III is not
passed?
c. RECOMMENDATION: Attachment 1 Section I Item 1 could read “... including
applicable regulatory authorities or governing bodies responsible for retail electric
service as described in Section III. A clearly defined statement allows the
Transmission Planner and Planning Coordinator to identify the appropriate parties
to be included in every instance Attachment 1 is used.

Response: 1. The SDT believes that affected stakeholders should include the list of NERC functional entities and others. Transmission
customers, Planning Coordinators, Transmission Planners, and regulatory authorities with retail jurisdiction should typically be
included. The SDT believes that the planning entity has the best understanding of who an affected stakeholder will be and that any
attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a
one size fits all approach. No change made.

Consideration of Comments: Project 2010-11

50

Organization

Yes or No

Question 2 Comment

2. a. Yes, it is the same as those in Section III.
b. Yes, these requirements are applicable for each circumstance of planned use of footnote b. The SDT believes that the use of the
stakeholder process is necessary each time that an entity utilizes footnote b.
c. The SDT did not accept your recommendation. The SDT believes that the suggested change may be too limiting since it refers to a
single governing body. No change made.
Western Area Power
Administration

No

A public process seems out of place in a reliability standard.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
Manitoba Hydro

No

A stakeholder process should not be required in jurisdictions where a legislation
already authorizes interruptions, as consent of stakeholders cannot override
legislation.

Response: The SDT does not believe that the consent of stakeholders will override legislation. The proposed process provides an
opportunity for affected stakeholders, including regulators, to have the necessary information to fully understand the impacts of the
planned use of footnote b. If the applicable regulator does not object to the planned use of footnote b, it may be used. No change
made.
Iberdrola USA

No

“Stakeholders” is undefined - would this be the same stakeholder body identified in
the planning process of the Open Access Transmission Tariff?

Response: In many instances, the affected stakeholders would be the same stakeholders identified in the Open Access Transmission
Tariff planning process. However, the SDT believes that the planning entity has the best understanding of who an affected
stakeholder will be and that any attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to
the necessity of having to adopt a one size fits all approach. No change made.

Consideration of Comments: Project 2010-11

51

Organization

Yes or No

Public Utility District No.1 of
Snohomish County

No

MEAG Power
City of Austin
Clark Public Utilities
Tacoma Power

Question 2 Comment
In the first sentence, remove the words “as an element of a Corrective Action Plan.”
There are cases on the fringes of the system where Non-Consequential Load Loss is
the preferred alternative in both the long term and short term, not as a temporary
patch. Requiring the stakeholder process as part of Corrective Action Plan implies
that using footnote 12 cannot be the long term choice. Since a Corrective Action
Plan is a “list of actions and an associated timetable for implementation to remedy a
specific problem,” using this term removes the stakeholders ability to evaluated the
costs and benefits and instead requires them to treat this a problem where the only
solution is building new facilities.

Response: The stakeholder process is not required as part of a Corrective Plan. What the attachment states is that use of the
footnote cannot be part of the Corrective Action Plan unless it has gone through the process. And the SDT disagrees that inclusion of
this language ever requires a construction solution. Bullet #7 in Section II requires that alternatives to Load shed be presented for
process participants to see as well as providing the rationale for not selecting those alternatives. Cost and benefits can certainly be
part of this rationale. No change made.
Ameren

No

It is our opinion that that the stakeholder process should be conducted at least once
every five years if non-consequential load is planned to be dropped as part of the
Corrective Action Plan to meet single contingency events. If conditions have not
materially changed since the last review, this information should still be
communicated to the stakeholders.

Response: The SDT did not want to present repetitive information and unduly burden the planning entity or the stakeholder in this
process. However, an entity can always do more than what is required in the standard. No change made.
Tri-State Generation &
Transmission Association

No

NERC Functional Model definitions for Planning Authorities and Transmission
Planners do not include the types of activities being proposed in “Attachment 1.”
How is it appropriate to mandate to functional entities functions that are outside
those defined in the NERC functional model?

Response: The NERC Functional Model is a guideline for activities required of cited functional entities. It is periodically updated as
Consideration of Comments: Project 2010-11

52

Organization

Yes or No

Question 2 Comment

conditions change. While the activities mentioned in the standard may not be explicitly spelled out in the NERC Functional Model,
the SDT does not believe that they are out of scope for either a Planning Coordinator or a Transmission Planner. No change made.
New England States Committee
on Electricity (NESCOE)

No

NESCOE appreciates the efforts of the SDT in developing a stakeholder process for
considering the use of load interruption in system planning. NESCOE especially
appreciates the heightened role accorded to states in light of jurisdictional issues
raised by the prospect of shedding load and implications for retail customers.
States must be intimately involved in weighing reliability considerations against the
economic implications of alternative approaches. Regarding the language in Section
I, see the comments above regarding striking “Near-Term” in this context.
NESCOE also suggests that additional clarity is needed regarding the intended
meaning of “applicable regulatory authorities or governing bodies responsible for
retail electric service issues.” This language potentially implicates state agencies
beyond public utility commissions (e.g., state consumer advocates, attorneys
general) and could create confusion for state agencies as well as transmission
planners that are required to provide notice to such entities and, pursuant to
Section III, provide a process for regulatory review. Instead, the SDT should revise
the language to read “electric retail regulatory authorities,” a term with clear
meaning that the Commission has itself used. See, e.g., Order 719.

Response: Please see the response to question 1.
The SDT believes that there may be instances where other regulatory bodies may want to be involved in the stakeholder process.
The SDT disagrees that the proposed language will create confusion for state agencies or transmission planners. The SDT believes
that the planning entity has the best understanding of who an affected stakeholder will be and that any attempt to codify a list of
such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a one size fits all approach.
No change made.
Independent Electricity System
Operator

No

Consideration of Comments: Project 2010-11

No. The process presented in Section I is overly prescriptive. If a section that
prescribes the principles of a stakeholder process is required, then for Canadian
entities this section should simply state that any threshold should be established in

53

Organization

Yes or No

Question 2 Comment
a manner consistent with other service levels that apply to local transmission and
retail service for the load to be curtailed.
Corrective action plans can rarely be implemented in a one-year time frame, and in
some cases, limited use of Non-consequential Load Loss will be preferable to
unaffordable transmission enhancements, therefore we believe that the use of
footnote ‘b’/’12’ should not be limited to the Near-Term Transmission Planning
Horizon. We propose that the phrase “the Near-Term Transmission Planning
Horizon of” be deleted from the opening paragraph.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
The SDT agrees that it may be difficult to implement construction options in a one year time frame and that the limited use of NonConsequential Load Loss may be an acceptable option. Footnote ‘b’ is not limited to Year One or to the Near-Term Transmission
Planning Horizon since the footnote recognizes that Firm Demand can be interrupted throughout the entire planning horizon. As
drafted, the standard defines the stakeholder process as mandatory for the Near-Term Transmission Planning Horizon since there
may not be time to implement other corrective actions but does not limit its use in the Long-Term Transmission Planning Horizon.
How individual entities reflect the Long-Term Transmission Planning Horizon situations in its individual stakeholder process is left to
the entity to determine. No change made.
Midwest Independent
Transmission System Operator,
Inc.

No

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our
comments under Question 5.

Response: Please see response to question 5.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT's response to Question 1 - stakeholder processes are not
appropriate for NERC standards.

Response: Please see response to question 1.

Consideration of Comments: Project 2010-11

54

Organization

Yes or No

Public Service Company of New
Mexico

No

Question 2 Comment
PNM voted yes to the Standard as a whole but would like the SDT to consider the
following concern: Part II.2.b of Attachment 1 that requires an assessment of the
effect of the use of Non-Consequential Load Loss under Footnote B on the health,
safety, and welfare of the community, and PNM believes that assessments of this
nature are entirely subjective and will be difficult to comply with and even more
difficult to audit. It is our belief that this criteria should be removed from the
Standard prior to its ultimate submittal to NERC.

Response: The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action
should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment A description of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
NB Power Transmission

No

The process in Attachment 1 is overly prescriptive. Attachment 1, if retained, needs
only to stipulate that the proposed utilization of the footnote be reviewed through
an open and transparent stakeholder process in compliance with the applicable
regulatory authority oversight.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
Hydro One Networks Inc.

No

The process presented in Section I is overly prescriptive. If a section that prescribes
the principles of a stakeholder process is required, then for non-US entities this
section should simply require that the process must be approved by the applicable
Regulatory Authority or Governmental Authority or its delegated agency that is
responsible for local transmission and retail service for the load to be curtailed in
that jurisdiction.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use

Consideration of Comments: Project 2010-11

55

Organization

Yes or No

Question 2 Comment

within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
LCRA Transmission Service
Corporation

No

Response: Without specific comments, the SDT is unable to respond.
Xcel Energy

Yes

The possibility of NCLL is always present, whether in the planning or operational
arena. Section I (#5) should however specifically state that in the dispute resolution
process a stakeholder does not have right of refusal for NCLL. This should be
especially true when a transmission project has been proposed and NCLL in the
interim is required due to the regulatory process, equipment lead time, etc.
preventing the completion of project at an earlier time.

Response: Bullet #5 does not require specific attributes of the dispute resolution process. The SDT believes that the attributes of the
stakeholder process should be defined by the entity during the development of the stakeholder process. No change made.
MRO NSRF

Yes

USACE
MidAmerican Energy Company

(1) In Attachment 1 Section I, what is the definition of a “stakeholder”? Which NERC
functional entities would be included (TO, TOP, LSE)? Are the public residential
and/or business owners that are affected included in the definition? Some parties
may assume that local government representatives or residential or business
owners are included as stakeholders. We believe it is most appropriate for the
Transmission Owners, Transmission Operators, and Load-Serving Entities to
objectively evaluate the risks of load shedding in a local area against the cost impact
of a large transmission project on the rate base. RECOMMENDATION: Define
stakeholder to be “affected Transmission Owners, Transmission Operators, and
Load-Serving Entities.”
(2) In Attachment 1 Section I item 1, what does “including applicable regulatory
authorities” refer to? Is this the same body that “applicable regulatory authority or
governing body” refers to in Section III? Are these requirements still applicable if the

Consideration of Comments: Project 2010-11

56

Organization

Yes or No

Question 2 Comment
25 MW threshold in Section III is not passed? RECOMMENDATION: Attachment 1
Section I Item 1 could read “... including applicable regulatory authorities or
governing bodies responsible for retail electric service issues as described in Section
III. A less vague statement allows the important parties to be included in every
instance Attachment 1 is used.

Response: (1) In many instances, the affected stakeholders would be the same stakeholders identified in the Open Access
Transmission Tariff planning process. However, the SDT believes that the planning entity has the best understanding of who an
affected stakeholder will be and that any attempt to codify a list of such stakeholders in the proposed standards could lead to errors
due to the necessity of having to adopt a one size fits all approach. No change made.
(2) The term applies to any applicable, interested regulatory authority and is not necessarily the same body as mentioned in Section
III. Conversely, the regulatory body cited in Section III would certainly be one of the regulatory bodies referred to in Section I. If the
result of Section I is that the entity is not going to move forward with the plan, then Section III will never occur. No change made.
Texas Reliability Entity

Yes

Attachment 1, section I (Stakeholder Process) should be clarified to specify which
‘responsible entity’ needs to utilize or develop a transparent stakeholder process.
For example, if a contingency event in Entity A’s system causes Entity B to have to
shed non-consequential firm load to meet the BES performance requirements,
which Entity is responsible for ensuring the required review? TRE proposes adding
the following sentence to the first paragraph to assign responsibility for this type of
scenario: “The Planning Coordinator or Transmission Planner accountable for the
contingency event will be responsible for implementing the stakeholder process and
regulatory review.”

Response: The SDT believes that the current terminology is clear in that it is the entity that plans to utilize the footnote that needs to
initiate the process. No change made.
California Independent System
Operator

Yes

Consideration of Comments: Project 2010-11

There is no basis to support only allowing the utilization of the footnote in the NearTerm Transmission Planning Horizon of the Planning Assessment. The footnote itself
should not explicitly restrict its utilization to only the Near-Term horizon. Often, in
the long-term planning horizon, when approval for transmission addition or
57

Organization

Yes or No

Question 2 Comment
reinforcement cannot be obtained for a variety of reasons, utilization of the
footnote is considered and adopted, subject to stakeholder’s and regulatory
authority’s approvals. Note that it is impractical to add or reinforce transmission
facilities in a near-term planning (e.g. Year One) time frame and hence the proposed
provision does not allow for utilizing the footnote for the interim period before new
or reinforced transmission facilities are put in place. We suggest to remove the word
“Near-Term”.

Response: Footnote ‘b’ is not limited to the Near-Term Transmission Planning Horizon since the footnote recognizes that Firm
Demand can be interrupted throughout the entire planning horizon. As drafted, the standard defines the stakeholder process as
mandatory for the Near-Term Transmission Planning Horizon since there may not be time to implement other corrective actions but
does not limit its use in the Long-Term Transmission Planning Horizon. How individual entities reflect the Long-Term Transmission
Planning Horizon situations in its individual stakeholder process is left to the entity to determine. No change made.
Southern California Edison
Company

Yes

The Stakeholder Process in Section I of Attachment 1 is similar to the method
effectively used by the CAISO to manage and incorporate stakeholder input in its
annual transmission planning process.

Platte River Power Authority

Yes

Although these descriptive steps for a public process seem out of place in a
reliability standard, Section 1 is in line with the planning principles of FERC Order
890.

Southwest Power Pool Reliability
Standards Development Team

Yes

Duke Energy

Yes

Bonneville Power Administration

Yes

Florida Municipal Power Agency

Yes

Consideration of Comments: Project 2010-11

58

Organization

Yes or No

Arizona Public Service Company

Yes

American Electric Power

Yes

Deseret Generation &
Transmission

Yes

American Transmission Company

Yes

Massachusetts Attorney General

Yes

Idaho Power Company

Yes

ISO New England

Yes

Georgia Transmission Corp

Yes

Modesto Irrigation District

Yes

Question 2 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11

59

3.

Do you agree with the Information for Inclusion in the Stakeholder Process contained in Section II of Attachment1? If you do not
support these changes or you agree in general but feel that alternative language would be more appropriate, please provide
specific suggestions in your comments.

Summary Consideration: Most of the commenters asked questions about the intent of the SDT in particular areas and the SDT has
provided individual responses accordingly.
There was one major overriding concern about Section II, Bullet 2b on the assessment on public health and safety. The SDT has clarified
its intent and also pointed out that the action required for this bullet item is analogous to what is already required in approved EOP-0012.1b.
Some commenters also questioned the use of the term ‘mitigate’ in Section II, Bullet 5. The SDT has clarified this language.
The following clarifying changes have been made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the health,
safety, and welfare of the community
Section II, Bullet #5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Organization

Yes or No

TVA Transmission Reliability
Engineering and Controls

No

Question 3 Comment
TVA would like to propose that this Stakeholder process be postponed in the event
that a transmission fix for a load drop issue was already planned within the next 2 or
3 years. Thus the stakeholder process would only occur for projects that had no fix
planned within the next couple of years.
TVA is also not sure how to satisfactorily address “health, safety, and welfare of the
community” - TVA would appreciate some guidance on how to properly address
this.

Consideration of Comments: Project 2010-11

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Organization

Yes or No

Question 3 Comment
TVA believes that item 1.b of Section II could contain CEII information and should
have limited distribution. The appropriate non-disclosure agreements would need to
be developed to prevent widespread publication of the information.

Response: ‘The SDT believes that the stakeholder process should occur whenever footnote ‘b’ is proposed to be utilized. The
construction option in later years will be a part of the information provided in the stakeholder process for review. In this case, there
will only need to be one review through the stakeholder process, if there are no material changes before the construction option is
completed. No change made.
The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action should be
analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect that
information while still providing the basics of the information needed for the process to continue. No change made.
ACES Power Marketing Standards No
Collaborators

(1) Adding the word “effect” on the health, safety, and welfare of the community
creates more confusion regarding what is needed for the assessment. We
recommend removing the effect clause from Section II.
(2) We disagree that the Transmission Planner should be required to provide an
assessment at all on the health, safety and welfare of the community. Attachment
1, Section 2a identifies the types of customers that are impacted without needing a
formal assessment. Stakeholders will have an opportunity to provide information
on impacts of planned load shedding through either the Transmission Planner’s
stakeholder comment process or through the local regulatory agency’s stakeholder
comment process. Further, these planned interruptions of firm demand are
expected to be short in nature so any impact would be de minimis. Finally, an
assessment on the health, safety and welfare of the community is an unnecessary
burden on the registered entity and is better suited for local governments that can
speak through the stakeholder process.

Consideration of Comments: Project 2010-11

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(3) Bullet 3 is based on available historical information. While this seems
reasonable, we have concerns because of the rare instances that Non-Consequential
Load Shed actually occurs. If a TP uses Non-Consequential Load Shed for the first
time, there is no historical information. What would be an acceptable basis for the
first use of Non-Consequential Load Shed when the entity is without historical
information?
(4) Expected time duration of the planned load shed is too speculative and should
not be required because any duration will likely be a guess. When actual
contingencies occur, the time of restoration varies and any time that was selected
prior to the event is not likely to be correct. We do not see the value in predicting
the duration time because there is too much uncertainty about how long an outage
will really last. The SDT needs to clarify what is expected for the duration of the
planned load shed.
(5) While we appreciate that the response to our comments clarified the intent is
that “Possible future plans could include a decision not to mitigate the need for Firm
Demand interruption,” the language in the Attachment simply does not reflect this.
The Attachment specifically states “Future plans to mitigate the need for NonConsequential Load Loss.” A decision not to mitigate the need for Firm Demand
interruption is not a future plan to mitigate. Consequently, Attachment 1, section
II.5 will need to be modified to implement this intent. Otherwise, this language is
certain to be interpreted as requiring a mitigation plan.

Response: (1) and (2) The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this
action should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
(3) Historical performance is not limited to Contingencies which result in Non-Consequential Load Loss. The estimated frequency
should be based on an entity’s average historical performance of similar Facilities applied to the specific Element being evaluated. No
change made.
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(4) The expected duration could be a range of values based on various assumptions. In the planning environment the entity should be
able to analyze the situation and determine an expected duration for which an interruption would be in place. No change made.
(5) The SDT agrees and has changed the language accordingly.
5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Minnkota Power Cooperative

No

1. MPC QUESTION/COMMENT: In Attachment 1 Section II item 2b, “Assessment of
the effect ... on the health, safety, and welfare of the community” is vague.
Clarification is requested.a. RECOMMENDATION: Remove Item 2b because it
requires the assessment of the footnote application impact on the potential health,
safety, and welfare of the community. These types of assessments should be
eliminated because they are not electric system reliability matters and were not
stipulated by FERC. In the event that the Standards Development teams choses to
keep item 2b, then add language semi-defining this as follows in Attachment 1
Section II Item 2b “...health, safety, and welfare of the community as determined by
impact on critical health and emergency services.” This allows the Transmission
Planner and Planning Coordinator to identify the appropriate parties affected by the
contingency to be analyzed in every instance Attachment 1 is used.

American Transmission Company

No

ATC recommends the following change in Section II of Attachment 1 applicable to
both standards TPL-002-1c [page 8] and TLP-001-2a [page16]:Remove Item 2b
altogether because it requires the assessment of the footnote application impact on
the potential health, safety, and welfare of the community. These types of
assessments should not be required in the Standards because they are not electric
system reliability matters and were not stipulated within the FERC Order762.

Bonneville Power Administration

No

BPA does not support including information under Section II.2.b, an assessment of
the use of Non-Consequential Load Loss on the health, safety, and welfare of the
community. It would be nearly impossible for a planner to predict this in a future
case since it is hard to predict what loads will actually materialize in the future. In
addition, this information does not support reliability of the BES since reliability of

Otter Tail Power Company

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Question 3 Comment
the transmission system is assessed by meeting required technical performance for
certain contingencies and under certain conditions.

Arizona Public Service Company

No

Item 2b: Reference to health, safety, and welfare is unnecessary. All demand
interruption are going to have some impact on health, safety, and welfare. The
impact is subjective and will simply result in unnecessary study reports by
consultants and will act as a road block.

Iberdrola USA

No

Regarding the documentation required for item 2.b, how are “health, safety, and
welfare of the community” to be assessed? What are the metrics? How would
compliance with this provision be evaluated?

MRO NSRF

No

Remove Item 2b because it requires the assessment of the footnote application
impact on the potential health, safety, and welfare of the community. These types
of assessments should be eliminated because they are not electric system reliability
matters and were not stipulated by FERC.

Southern California Edison
Company

No

SCE participates in the rigorous CAISO annual transmission planning process that
considers the information included in the proposed Section II of Attachment 1.
However, the proposed language in Section II.2.b. “Assessment of the effect of Firm
Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community,” seems overly broad and confusing. The California Public Utility
Commission (CPUC) and CAISO presently consider these items before approving
transmission plans. It is unclear what type of information would be required in order
to meet the seemingly broad request contained in Section II.2.b. SCE believes that
the language of Section II.2.b. should be removed from Attachment 1, or
alternatively, the language should be revised to specifically exempt critical loads,
such as hospitals, fire department facilities, law enforcement facilities, and
correctional facilities.

Public Utility District No.1 of

No

We suggest removing section 2b “Assessment...health, safety...” for three reasons:

MidAmerican Energy Company
USACE

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Yes or No

Snohomish County

1)All outages have a negative impact on the community. Outages under footnote 12
do not inherently have more significant impact per MWhr lost than other outages
allowed per Table 1. By requiring additional analysis for a similar societal impact,
this provision discriminates against utilities at the fringes of the system. 2) While
reminding planners to consider that their decisions do have real impacts to real
people is a laudable goal, including this provision opens the door to significant legal
liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place
to introduce such a significant requirement. The Adequate Level of Reliability Task
Force would be a more appropriate venue for this idea.

MEAG Power
Clark Public Utilities

Tacoma Power

Question 3 Comment

No

City of Austin

We suggest removing section 2b “Assessment...health, safety...” for three reasons:
1)All outages have a negative impact on the community. Outages under footnote 12
do not inherently have more significant impact per MWhr lost than other outages
allowed per Table 1. By requiring additional analysis for a similar societal impact,
this provision discriminates against utilities at the fringes of the system. 2) While
reminding planners to consider that their decisions do have real impacts to real
people is a laudable goal, including this provision opens the door to significant legal
liability and regulatory uncertainty. 3) An appendix to a footnote is the wrong place
to introduce such a significant requirement. The Adequate Level of Reliability Task
Force would be a more appropriate venue for this idea.

Response: The SDT understands the concerns and has clarified the wording accordingly. The intent of the SDT is that this action
should be analogous to that required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
Tri-State Generation &
Transmission Association

No

Consideration of Comments: Project 2010-11

In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that
the end-use customer makes available to its Load-Serving Entity via contract or
agreement for curtailment.” The process described in Attachment 1 creates an
agreement between stakeholders (aka “end-use customers”) and their transmission
providers. Thus, if the process described in Attachment 1 is followed, the “Firm
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Question 3 Comment
Demand” referenced would be reclassified as “Interruptible Demand.” In essence,
“Footnote b” does not allow the interruption of Firm Demand. It merely requires
that if interruption of Demand is required, it can only be Interruptible Demand. If
this was the intention of FERC, NERC, and the Drafting Team, why didn’t the drafting
team just state “Interruption of Firm Demand is not allowed”?

Response: Upon reviewing the comments, the SDT has seen that a clarification for Demand that is not included as Firm Demand for
footnote ‘b’ could be clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Independent Electricity System
Operator

No

No. The process presented in Section II is overly prescriptive. If a section that
prescribes the information requirements for a stakeholder process is required, then
for Canadian entities this section should simply state that any threshold should be
established in a manner consistent with other service levels that apply to local
transmission and retail service for the load to be curtailed.

Hydro One Networks Inc.

No

The process presented in Section II is overly prescriptive. If a section that prescribes
the information requirements for a stakeholder process is required, then for non-US
entities this section should simply require that the process information
requirements must be in accordance with the requirements of the applicable
Regulatory Authority or Governmental Authority or its delegated agency that is
responsible for local transmission and retail service in that jurisdiction.

Response: Canadian entities are allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use
within the confines of provincial regulations. Nothing has changed in that regard with this proposed standard. The effective date
language covers the situation. No change made.
Midwest Independent
Transmission System Operator,

No

Consideration of Comments: Project 2010-11

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our

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Inc.

Question 3 Comment
comments under Question 5.

Response: Please see response to question 5.
Electric Reliability Council of
Texas, Inc.

No

Please see ERCOT's response to question 1-the NERC Reliability Standards should
not contain requirements related to stakeholder processes, whether they are
procedural or substantive. If an exception process is retained, it should be outside of
the NERC Reliability Standards (e.g. in the Rules of Procedure). To the extent the
proposed standard inappropriately retains the stakeholder related aspects, ERCOT
also provides the following comments on Section II-the ERCOT comments are in
parentheses for easy reference and distinction relative to the proposed
requirements.II. Information for Inclusion in Item #3 of the Stakeholder ProcessThe
responsible entity shall document the planned use of Firm Demand interruption
under footnote 'b' which must include the following: (ERCOT COMMENT: This is all
that is needed for this. The documentation would be relative to the objective
criteria developed for this purpose.)
1. Conditions under which Firm Demand interruption under footnote 'b' would be
necessary:a. System Load level and estimated annual hours of exposure at or above
that Load levelb. Applicable Contingencies and the Facilities outside their applicable
rating due to that Contingency(ERCOT COMMENT: "1" is not necessary if objective
criteria are developed as benchmarks for the exception process. In that case,
exceptions would only be allowed if the objective criteria were met, regardless of
the underlying assumptions related to conditions and contingencies.)
2. Amount of Firm Demand MW to be interrupted with:a. The estimated number
and type of customers affectedb. Assessment of the effect of the use of Firm
Demand interruption under footnote 'b' on the health, safety, and welfare of the
community(ERCOT COMMENT: The considerations reflected in a and b are
inappropriate for a reliability standard. Appropriate considerations for reliability
standards are related to the reliability performance of the system. The
considerations in a and b are more akin to quality of service issues better suited for

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Yes or No

Question 3 Comment
regional policy discussions. It is not within the purview of the SDT to address those
matters.)
3. Estimated frequency of Firm Demand interruption under footnote 'b' based on
historicalPerformance (ERCOT COMMENT: Historical performance is irrelevant. If
the SDT is going to retain revisions that accommodate non-consequential load
shedding, then the only relevant metrics are the objective criteria that set the
benchmarks for such exceptions.)
4. Expected duration of Firm Demand interruption under footnote 'b' based on
historical performance(ERCOT COMMENT: See ERCOT response to "3" above.)
5. Future plans to mitigate the need for Firm Demand interruption under footnote
'b'(ERCOT COMMENT: This is redundant to the requirement in the reliability
standards that requires a plan to resolve any violations identified in the planning
process.Furthermore, if load shedding is allowed, this requirement doesn't make
sense. Presumably the idea behind allowing these exceptions is to obviate the
prospective need for other alternatives. If that is not the case, then there is no need
to allow the exceptions, because the transmission upgrades to mitigate the need for
load shedding can be established in the planning horizon.)
6. Verification that TPL Reliability Standards performance requirements will be met
following the application of footnote 'b'(ERCOT COMMENT: The basis for the load
shedding exception is to provide a means to meet the TPL performance
requirements in the context of a planning assessment. Accordingly, this is redundant
to the planning assessments, the point of which is to identify and resolve
performance issues.)
7. Alternatives to Firm Demand interruption considered and the rationale for not
selecting those alternatives under footnote 'b'(ERCOT COMMENT: Load shedding
exceptions should be based on objective criteria and be reviewed pursuant to a
process external to the NERC reliability standards. Alternative discussions could be
part of that external process.)

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Question 3 Comment
8. Assessment of potential overlapping uses of footnote 'b' including overlaps with
adjacent Transmission Planners and Planning Coordinators(ERCOT COMMENT: It is
not clear what this means. Each functional entity performs assessments relative to
its own system. This appears to introduce a vague regional transmission planning
requirement with no structure or rules for such assessments.)

Response: Please see response to question 1.
The SDT believes that the criteria in Section II are objective and represent the information that a stakeholder will want to see for
assistance in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve
some parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
The SDT has revised the language of bullet #5 due to other comments received.
5. Future plans to mitigate alleviate the need for Firm Demand interruption under footnote ‘b’
Bullet #8 does not introduce a regional planning requirement. It is consistent with Requirement R8 in proposed TPL-001-2a that
mandate sharing of Planning Assessments. No change made.
Xcel Energy

No

Section II should be left as part of the resolution in the dispute process and should
not be made a requirement. Some in particular include:§ II.1. - this should be
based only on applicable contingencies or conditions that could require NCLL.
Having to include the estimated hours at or above a load level may not always be
the most effective way to convey why NCLL will be used and adds little to the
argument of why or why not it needs to be used.
§ II.2.a - This may not always be apparent to the TO serving a wholesale
transmission customers (REC, MUNICIPAL, etc.). This should be eliminated since it
does little in emphasizing the need for NCLL.
§ II.2.b - The "effect" of the use of NCLL may not always be apparent, because it is
a perceived condition of what could happen that can be interpreted differently. I
agree that it should be mentioned in the Stakeholder process outlining the locations

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Question 3 Comment
where NCLL will take place and let the dispute process identify and assess the
health, safety and welfare of the community. How do you assess the effect in the
Planning of NCLL. The effect should be identified by the party being affected and
resolved in the dispute process.
§ II.3 & 4. - This needs to be eliminated. Expected frequency and duration of NCLL
based on historical performance DOES NOT GUARANTEE future performance and
does little in emphasizing the need for NCLL.
II.8 - This should be addressed by the Regional Planning Authority in their regional
studies.

Response: The SDT disagrees and believes that the criteria in Section II represent the information that a stakeholder will want to see
for assistance in determining their position on proposed planned actions. The SDT reminds the commenter that this process will
involve some parties that are not experts in interpreting assessments and that these parties will need information that may be
considered redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change
made.
ISO New England

No

Consideration of Comments: Project 2010-11

Section II, 2.a states that studies must address the estimated number and type of
customers affected by Non-Consequential Load Shedding. This language should be
removed for three reasons.(1) This appears to be inappropriate for a reliability
standard. The specific number and type of customers within a set number of MWs
that are electrically acceptable do not impact the reliability of the bulk electric
system (as defined by Section 215 of the Federal Power Act). (2) Even if the number
and type of affected customers were an appropriate process question for an ERO
standard, the number and type of customers may change depending on particular
system configuration at the time of the load shedding. For example, a substation
may be reconfigured to address other system issues such as maintenance and a
certain number of MWs of load being interrupted, while still electrically acceptable
from a system reliability perspective, may impact different numbers and types of
customers. (3) Assuming that the number and type of customers affected were an
appropriate metric, the Transmission Planner in many cases will not be the
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appropriate entity to address these concerns. The Transmission Owner, Distribution
Provider or Load Serving Entities would be the appropriate entities to address
customer affects.
Section II, 2.b should be revised to delete the reference to “health, safety, and
welfare of the community.” It is inappropriate for a NERC Standard to require
planners to address the “health, safety, and welfare of the community.” NERC’s
authority appears limited to regulating the “reliability” of the bulk electric system.
Section 215 specifies that NERC’s authority it to establish Reliability Standards
necessary to ensure an “adequate level of reliability.” Reliability Standards may
specify the “design of planned additions or modifications to such facilities to the
extent necessary to provide for reliable operation.” Section 215 defines “reliable
operation” as “operating the elements of the BPS within equipment and electrical
system thermal, voltage, and stability limits so that instability, uncontrolled
separation, or cascading failures of such system will not occur as a result of a sudden
disturbance, including a cybersecurity incident, or unanticipated failure of system
elements.” Establishing this requirement is also arbitrary, because it is
inconsistent with other transmission planning requirements. For example, the same
load could be shed directly as the consequence of a fault and no such assessment is
required. In addition, Transmission Planners can plan for the shedding of radial load
with no assessment of health, safety and welfare.
Section II, requirements 3 and 4 discuss estimating frequency and duration of NonConsequential Load Loss based on historical performance. This provision is
inconsistent with the manner in which transmission system planning is conducted
and should be removed. The transmission system planning process uses
deterministic not probabilistic assessments. While a power system may utilize these
factors in assessing where the use of non-consequential load loss may be acceptable
in terms of providing service, these factors do not inform reliability risks to the bulk
electric system where the loss of load is found to be electrically acceptable in terms
of system reliability (i.e., no thermal, voltage, or stability issues are created or

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Question 3 Comment
exacerbated and no instability, uncontrolled separation, or cascading failures result).

Response: The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance
in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some
parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
The SDT understands the concerns and has clarified the wording. The intent of the SDT is that this action should be analogous to that
required in approved EOP-001-2.1b.
Section II, Bullet 2b. Assessment An explanation of the effect of the use of Firm Demand interruption under footnote ‘b’ on the
health, safety, and welfare of the community
The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance in
determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some parties
that are not experts in interpreting assessments and that these parties will need information that may be considered redundant or
superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
SCE&G

No

We believe that item 1.b of Section II may contain Critical Energy Infrastructure
Information (CEII) and should have limited distribution. The appropriate nondisclosure agreements would be required in order to prevent widespread
publication of the information.

SERC EC Planning Standards
Subcommittee

No

We believe that item 1.b of Section II would contain CEII information and should
have limited distribution. The appropriate non-disclosure agreements would need to
be developed to prevent widespread publication of the information.

Associated Electric Cooperative

Response: If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect
that information while still providing the basics of the information needed for the process to continue. No change made.
NBSO

No

Consideration of Comments: Project 2010-11

We do not agree with the need for Section II (and Attachment I as a whole) at all.
The footnote, or Attachment I, should only stipulate that when Non-Consequential
Load Loss is needed to ensure that BES performance requirements are met, then
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Question 3 Comment
regulatory approval from local jurisdiction needs to be provided with demonstration
that the approval was obtained through an open stakeholder process.

Response: The SDT believes that the criteria in Section II represent the information that a stakeholder will want to see for assistance
in determining their position on proposed planned actions. The SDT reminds the commenter that this process will involve some
parties that are not experts in interpreting assessments and that these parties will need information that may be considered
redundant or superfluous in other settings. Items such as historical performance would fall into this realm. No change made.
LCRA Transmission Service
Corporation

No

NB Power Transmission

No

Response: Without specific comments, the SDT is unable to respond.
Texas Reliability Entity

Yes

In Section II, part 1b, TRE suggests replacing ‘applicable rating’ with ‘steady state
performance requirments’, to account for all the BES performance requirements (in
particular, steady-state and post-contingency voltages) for which the footnote may
be utilized.

Response: Applicable ratings are the basis for the performance requirements in Table 1 of proposed TPL-001-2a. Therefore, the SDT
believes that the existing terminology correctly addresses the performance issue. No change made.
Southwest Power Pool Reliability
Standards Development Team

Yes

In this section the reference to Customers should only be Customers of Transmission
and not open ended for any customer. Once it is sold wholesale the TP wouldn’t
know where it is being sent to. We would also note that under some jurisdictions
that there is a minimum duration threshold for keeping historical data on some of
these events that are being requested under this section. Need to add language to
accommodate these thresholds so as not to contradict what is being asked for by
the regulatory bodies.

Response: The SDT disagrees that the only customers that should be considered are wholesale customers. The total number of
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Question 3 Comment

customers affected is information that helps other stakeholders understand the full impact of the planned usage of footnote ‘b’. The
SDT also disagrees that the Transmission Planner will not know where the Load will be lost. The Transmission Planner cannot
evaluate the impacts of interrupting Firm Demand without knowing where the Load is connected to the BES system. The historical
information is not related to historical planned Load interruption, but rather the historical performance of similar Facilities.
However, If an entity does not have its own historical information available then it should use other available data to make its best
estimate of what the values will be. No change made.
New England States Committee
on Electricity (NESCOE)

Yes

NESCOE agrees with the list provided in Section II. Regarding item #7, in the interest
of explicit direction, NESCOE suggests adding at the end of the sentence the
following language: “and cost comparisons of all alternatives.”

Response: Cost considerations will be part of a rationale for selection or non-selection of an alternative. The SDT believes the
current terminology captures this concept. No change made.
Ameren

Yes

We believe that item 1b of Section II would contain critical electric infrastructure
information (CEII) and should have limited distribution. The appropriate nondisclosure agreements would need to be developed to prevent widespread
publication of the material.

Response: If an entity believes that CEII information is involved then the entity should use the appropriate mechanisms to protect
that information while still providing the basics of the information needed for the process to continue. No change made.
Duke Energy

Yes

Florida Municipal Power Agency

Yes

Lakeland Electric
Gainesville Regional Utilities
Southern Company

Yes

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Yes or No

Western Area Power
Administration

Yes

American Electric Power

Yes

Seminole Electric Cooperative,
Inc.

Yes

Deseret Generation &
Transmission

Yes

Platte River Power Authority

Yes

Massachusetts Attorney General

Yes

California Independent System
Operator

Yes

Public Service Company of New
Mexico

Yes

Idaho Power Company

Yes

Georgia Transmission Corp

Yes

Modesto Irrigation District

Yes

Question 3 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11

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4.

Do you agree with the text in Section III of Attachment 1? If you do not support these changes or you agree in general but feel
that alternative language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The majority of the comments received here are similar to those submitted for question 1 and similar
responses have been provided.
The following clarifying changes were made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure ensure that the
applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues does not object to the
use of Firm Demand interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority authorities or
governing bodybodies responsible for retail electric service issues does not object to the use of Firm Demand interruption under
footnote ‘b’, 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 ‘b’ for Firm
Demand interruption.
Organization

Yes or No

Public Utility District No.1 of
Snohomish County

No

MEAG Power
City of Austin
Clark Public Utilities

Consideration of Comments: Project 2010-11

Question 4 Comment
1) Similar to our comment on question 2, please remove the words “as an element
of a Corrective Action Plan” from the first sentence. There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in
both the long term and short term, not as a temporary patch. Since a Corrective
Action Plan is a “list of actions and an associated timetable for implementation to
remedy a specific problem,” using this term removes the stakeholders ability to
evaluate the costs and benefits and instead requires them to treat this a problem
where the only solution is building new facilities.
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2) For any specific use of footnote b, there could be several applicable regulatory
authorities such as small municipalities or public utility districts. The standard
should clarify whether the planner must show evidence that every authority did not
object, or whether the planner only needs to show that less that 25 MW was not
rejected by the regulatory authorities. To accomplish this clarification, we propose:
A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or
governing body” to “regulatory authorities or governing bodies.” B) Add a sentence
to bullet 2 to read “If multiple regulatory authorities or governing bodies are
responsible for retail electric service issues, only the portion of Non-Consequential
Load Loss exceeding 25 MW is subject to section III.”

Tacoma Power

No

1) Similar to our comment on question 2, please remove the words “as an element
of a Corrective Action Plan” from the first sentence. There are cases on the fringes
of the system where Non-Consequential Load Loss is the preferred alternative in
both the long term and short term, not as a temporary patch. Since a Corrective
Action Plan is a “list of actions and an associated timetable for implementation to
remedy a specific problem,” using this term removes the stakeholders ability to
evaluate the costs and benefits and instead requires them to treat this a problem
where the only solution is building new facilities.
2) For any specific use of footnote b, there could be several applicable regulatory
authorities such as small municipalities or public utility districts. The standard
should clarify whether the planner must show evidence that every authority did not
object, or whether the planner only needs to show that less that 25 MW was not
rejected by the regulatory authorities. To accomplish this clarification, we propose:
A) In Section III paragraph 1 and paragraph 5 change “regulatory authority or
governing body” to “regulatory authorities or governing bodies.” B) Add a sentence
to bullet 2 to read “If multiple regulatory authorities or governing bodies are
responsible for retail electric service issues, only the portion of Non-Consequential
Load Loss exceeding 25 MW is subject to section III.”

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Yes or No

Question 4 Comment

Response: (1) The SDT disagrees. When alternatives and the rationale for selection or non-selection of those alternatives are
presented, cost factors can certainly be part of the rationale. In proposed TPL-001-2a, Requirement R2, Part 2.7.1, a list of possible
actions that could be included in a Corrective Action Plan is provided. This list shows several alternatives that do not require the
building of new Facilities. No change made.
(2) The SDT agrees that the plural use of the terms shown in A) above should be consistent throughout the document and has made
corresponding changes to reflect this. The SDT does not agree with the proposed change shown in B). The footnote is applicable for
a single Contingency and ownership or jurisdictional concerns do not come into play. The total value of Load affected by the single
Contingency is the correct value to determine if the situation is subject to Section III.
Attachment 1, Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a
Corrective Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure
ensure that the applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues
does not object to the use of Firm Demand interruption under footnote ‘b’ if either:
Attachment 1, Section III, last paragraph: Once assurance has been received that the applicable regulatory authority authorities
or governing bodybodies responsible for retail electric service issues does not object to the use of Firm Demand interruption
under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
MRO NSRF

No

USACE

(1) In Attachment 1 Section III, what is the definition of “applicable regulatory
authority or governing body”? Is this the state PSC or PUC? Is it the Regional
Reliability Organization (RRO)? Is it the Reliability Coordinator (RC)?
RECOMMENDATION: Depending on the answer to the above question, define
“applicable regulatory authority or governing body” more precisely. The language
could read “applicable regulatory authority or governing body responsible for retail
electric service such as the state Public Services Commission or Public Utilities
Commission”. A less vague statement allows the important parties to be included in
every instance Attachment 1 is used.
(2) In Attachment 1, if non-consequential load loss is planned at multiple bulk
delivery points to mitigate the same contingency should the total load loss count

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Question 4 Comment
towards the 25 MW and 75 MW thresholds or should the loads be counted
individually? EXAMPLE: There are two load serving substations (X load at substation
B and Y load at substation C) on a long 115 kV line with 230/115 kV transformation
at each end (substation A and substation D). Automatic under-voltage load shedding
is in place at substations B and C, the UVLS relays at each substation making load
trip decisions based on local voltage (i.e. independent operation). If one end of the
115 kV line trips and 115 kV voltage is below allowable levels at both substations X
and Y, then the total load tripped by UVLS will be X+Y. Does the X+Y value count
towards the 25 MW and 75 MW thresholds or are X and Y counted separately?
What if X load is dropped for one contingency and Y load is dropped for a different
contingency, is the total load counted X+Y or each load separately?
RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’ could
read “In no case can the planned Firm Demand interruption under footnote ‘b’
exceed 75 MW for any single contingency.” Similar language could be added in
Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the
two thresholds and decrease confusion.
(3) If non-consequential load loss is planned at multiple bulk delivery points in close
proximity to mitigate different contingencies should the total load loss count
towards the 25 MW and 75 MW thresholds or should the loads be compared
individually? For example, there are two load serving substations (X load at
substation B and Y load at substation C) on a networked 115 kV line with 230/115
kV transformation at both ends (substation A and substation D). Automatic undervoltage load shedding is in place at substations B and C that would trip X amount of
load if one end of the 115 kV line tripped and 115 kV voltage was below allowable
levels, and would trip Y amount of load if the other end of the 115 kV line tripped
and 115 kV voltage was below allowable levels. Does the X+Y value count towards
the 25 MW and 75 MW thresholds or are X and Y counted separately? In addition to
the aforementioned contingencies, if the 115 kV line between substations B and C
opens, both loads X and Y will trip. Now does the X+Y value count towards the 25

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Question 4 Comment
MW and 75 MW thresholds?
(4) In Attachment 1, if UVLS relaying is programmed at a sub to trip the load in
stages at multiple voltage setpoints, such that only a fraction of the load is tripped
for a given contingency, is the entirety of the load still counted towards the 25 MW
and 75 MW thresholds? EXAMPLE: Substation B has X load that will trip if the BES
voltage gets to 0.92 p.u. and Y that will trip if the BES voltage gets to 0.88 p.u. If only
X amount of load is required to mitigate a single contingency in the near-term TPL
assessment, is X load counted towards the 25 MW and 75 MW thresholds or is X+Y
load counted? Is there a difference if the Y load is at a different, nearby substation
with both loads having the aforementioned tripping logic? RECOMMENDATION: In
TPL-002-1c, the last sentence in Table I footnote ‘b’ could read “In no case can the
planned Firm Demand interruption under footnote ‘b’ (as demonstrated in the nearterm horizon analysis) exceed 75 MW.” Similar language could be added in
Attachment 1 Section III in regards to the 25 MW and 75 MW thresholds and in TPL001-2a as well. This would explain much more clearly what is counted towards the
two thresholds and decrease confusion

Minnkota Power Cooperative

No

Otter Tail Power Company

1. MPC QUESTION: In Attachment 1 Section III, what is the definition of “applicable
regulatory authority or governing body”? a. Is this the state Public Service
Commission or Public Utilities Commission, the Regional Reliability Organization
(RRO), and/or the Reliability Coordinator (RC)? b. RECOMMENDATION: Depending
on the answer to the above question, define “applicable regulatory authority or
governing body” more precisely. The language could read “applicable regulatory
authority or governing body responsible for retail electric service such as the state
Public Services Commission or Public Utilities Commission”. A clearly defined
statement allows the Transmission Planner and Planning Coordinator to identify the
appropriate parties to be included in every instance Attachment 1 is used.
2. MPC QUESTION: In Attachment 1, if non-consequential load loss is planned at
multiple bulk delivery points to mitigate the same contingency should the total load
loss count towards the 25 MW and 75 MW thresholds or should the loads be

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Question 4 Comment
counted individually? a. EXAMPLE: There are two load serving substations (X load at
substation B and Y load at substation C) on a long 115 kV line with 230/115 kV
transformation at each end (substation A and substation D). Automatic undervoltage load shedding is in place at substations B and C, the UVLS relays at each
substation making load trip decisions based on local voltage (i.e. independent
operation). If one end of the 115 kV line trips and 115 kV voltage is below allowable
levels at both substations X and Y, then the total load tripped by UVLS will be X+Y. i.
Does the X+Y value count towards the 25 MW and 75 MW thresholds or are X and Y
counted separately? ii. What if X load is dropped for one contingency and Y load is
dropped for a different contingency, is the total load counted X+Y or each load
separately? b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I
footnote ‘b’ could read “In no case can the planned Firm Demand interruption
under footnote ‘b’ exceed 75 MW for any single contingency.” Similar language
could be added in Attachment 1 Section III in regards to the 25 MW and 75 MW
thresholds and in TPL-001-2a as well. This clarification would explain much more
clearly what is counted towards the two thresholds and decrease confusion.
3. MPC QUESTION: In Attachment 1, if UVLS relaying is programmed at a sub to trip
the load in stages at multiple voltage setpoints, such that only a fraction of the load
is tripped for a given contingency, is the entirety of the load still counted towards
the 25 MW and 75 MW thresholds? a. EXAMPLE: Substation B has X load that will
trip if the BES voltage gets to 0.92 p.u. and Y that will trip if the BES voltage gets to
0.88 p.u. i. If only X amount of load is required to mitigate a single contingency in
the near-term TPL assessment, is X load counted towards the 25 MW and 75 MW
thresholds or is X+Y load counted? ii. Is there a difference if the Y load is at a
different, nearby substation with both loads having the aforementioned tripping
logic? b. RECOMMENDATION: In TPL-002-1c, the last sentence in Table I footnote ‘b’
could read “In no case can the planned Firm Demand interruption under footnote
‘b’ (as demonstrated in the near-term horizon analysis) exceed 75 MW at a single
substation.” Similar language could be added in Attachment 1 Section III in regards
to the 25 MW and 75 MW thresholds and in TPL-001-2a as well. This would explain

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Question 4 Comment
much more clearly what is counted towards the two thresholds and decrease
confusion.

Response: (1) The SDT believes that any attempt to more specifically enumerate regulatory bodies will result in the exact opposite
effect of what is stated in that inevitably there will be a one-off situation that doesn’t fit the statement. The SDT believes that the
entity will know who needs to be involved and will take the appropriate steps to make certain that the correct parties are involved.
No change made.
(2) Footnote ‘b’ only applies to single Contingencies so the SDT believes that adding the suggested words would be redundant. In the
specific example cited, if the actions taken are the result of the same single Contingency, then the total value of the Load shed would
be applicable. No change made.
(3) If the Load shed is the result of different Contingencies, the proximity doesn’t matter and the Load would be counted separately.
(4) The SDT believes that the suggested wording would be redundant. Only Load shed due to a single Contingency is applicable here.
No change made.
ACES Power Marketing Standards
Collaborators

No

(1) We disagree with the threshold of 75 MW, as mentioned above.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
Southern California Edison
Company

No

Consideration of Comments: Project 2010-11

As applied to SCE’s service territory, Section III of Attachment 1 appears to require
written acknowledgement and approval by the CPUC of each and every Firm
Demand interruption authorized by the CAISO’s annual transmission plan. In
California, the CPUC is notified of and invited to every CAISO meeting on
transmission planning, but the CPUC generally does not provide specific written
assurances or agreement on detailed elements of the CAISO transmission plan. SCE
believes that a general approval of the overall plan from the regulatory body should

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Question 4 Comment
be adequate.

Response: The SDT disagrees that formal approval is required for every instance of Firm Demand interruption as Section III only
applies for Load over 25 MW. Obtaining assurance from regulators that they do not object will undoubtedly occur in different ways.
Some regulators may provide written assurances or agreement but that is not required by the standard. No change made.
Bonneville Power Administration

No

For use of Non-Consequential Load Loss in Year One of the Planning Assessment,
BPA believes that assurance received from the applicable regulatory authority or
governing body responsible for retail electric service issues is adequate and
submission to the ERO for a determination of adverse impact is unnecessary. The
local utility and regulators are better positioned to determine adverse impacts on
an individual system, whereas the ERO would have to develop a process and criteria
for assessing adverse impacts.

Response: The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The
ERO is aware of the proposed responsibility and has accepted this role if the industry approves. No change made.
Tri-State Generation &
Transmission Association

No

How would section III of “Attachment 1” be applied to entities that only deliver
wholesale electric service and no retail electric service?

Response: The SDT believes that the wholesale customer will be one of the stakeholders included in the process and any use of the
footnote must go through the stakeholder process. No change made.
Modesto Irrigation District

No

Consideration of Comments: Project 2010-11

I am voting NO because there is no technical basis for use of the 75 and 25 MW
absolute threshold values, regardless of the size of the utility's load, referenced in
the proposed standard. WECC's past experience with implementation of arbitrary
magnitudes for requirements (e.g., the 5% and 7% arbitrary magnitude contingency
reserve requirements), has proved to be problematic. I would suggest investigating
a technical basis for using a relative requirement, such as percentage of the utility's
load, maybe 5% and 2.5%, respectively, and that it be based on technical
requirements similar to those found in Table 1 of the WECC Criteria TPL-001-WECC-

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Question 4 Comment
CRT-2.Thank you.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Utilizing a percentage of an entity’s Load may be
problematic – when dealing with a small entity it could be a small value but still of rather large import and if dealing with a large
entity could result in significant amounts of Load shed being planned. And, the FERC Order states that a percentage approach would
not be appropriate for the aforementioned reasons. The SDT believes that any deviation from the threshold derived from the actual
data may be viewed as a non-acceptable least common denominator approach. No change made.
Electric Reliability Council of
Texas, Inc.

No

If non-consequential load shedding is allowed for single contingency conditions, as
discussed above, it should be based on objective critieria. As such, there is no need
for the proposed stakeholder process, including the Section Ill instances requiring
regulatory review.
Furthermore, establishing approval roles in planning processes for entities other
than the relevant functional entities conflicts with the appropriate roles, and
appropriate separation of those roles, of the relevant entities (i.e. the planning
authority and the state regulatory body and NERC RE). Typically a functional entity
performs the functional activity, and others relevant to the proposed process in the
standard perform compliance and regulatory oversight of the functional
performance. This is a practical concern, and also potentially raises conflicts
between governing authorities that create the separation of roles, where, typically,
the relevant authorities establish a functional entity as the planning entity, and
NERC and its REs and state regulators (as relevant - e.g. in ERCOT) are charged with
compliance and regulatory oversight. As with the other stakeholder process
sections, that section should be eliminated.

Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted

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Question 4 Comment

draft added detail and specificity to the already approved approach. No change made.
The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. While formal
approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not require formal
approval but rather a lack of dissent. No change made.
National Association of
Regulatory Utility Commissioners

No

It appears that the 25 MW minimum value is merely a reflection of antidotal
information from a small number of data request responders and as such is not
technically justified. NARUC is not poised to offer an alternative; given that the
State/local regulator is consulted in this process, States should be appraised if any
load is anticipated to be shed under any planning criteria. Thus, no mimimum value
should be set.

Response: The data request is not anecdotal information. All of the Transmission Planners in the continental United States supplied
their data in response to the data request. The SDT believes it is unrealistic to consider the allowable usage of footnote ‘b’ in the
planning process without a cap on the amount of Load planned to be shed. The SDT also believes that such a position is consistent
with the wording in the Order. Absent any alternative suggestion and given the participation of appropriate regulatory bodies in
both Sections I and III, the SDT believes that the current threshold is the best possible solution. No change made.
Xcel Energy

No

It does not appear that an entity has any options if the applicable regulatory
authority or governing body objects to the use of NCLL in year one. This could
potentially occur as a result of load patterns and generation issues submitted by an
LSE not necessarily having BES elements and the only solution is to implement NCLL.
In year one, it is too late to build any necessary and NCLL may be the only
alternative.

Response: While the requirement is not mandatory until Year One, the SDT believes that it would be a good practice to move
forward as soon as an entity knows it is contemplating usage of the footnote. That way, alternatives can be openly discussed before
time becomes an overriding concern. The instance described above points to the need for the stakeholder process as this process
will facilitate closer coordination with the Load-Serving Entities providing the information and the applicable regulators. No change
made.

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MidAmerican Energy Company

No

Question 4 Comment
Item III of Attachment I should be deleted completely. Non ERO regulatory review is
not necessary. Applicable regulatory authority or governing bodies responsible for
retail electric service issues are stakeholders which may participate in the
stakeholder process. Further, there are concerns compliance may not be possible
because item III makes non-NERC applicable regulatory authorities or governing
bodies responsible for retail electric service issues part of a NERC mandatory
compliance without consequence to the said non-NERC governing bodies. NonNERC entities are not constrained by NERC mandatory laws and penalties and aren't
compelled to perform actions to meet NERC compliance. This opens a risk to any
NERC regulated entities governed by such regulatory or governing bodies that do
not or may not feel compelled to have a process for the NERC regulatory review
specified in item III of attachment I.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today.
While formal approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not
require formal approval but rather a lack of dissent. No change made.
New England States Committee
on Electricity (NESCOE)

No

NESCOE is concerned that the 25 MW minimum value for regulatory review lacks
sufficient technical justification. NESCOE understands that the SDT used responses
to data requests to establish this 25 MW value, which is based on the average
number of MWs that entities applying footnote “b” reported using in transmission
planning. This may be a good starting point, but additional analysis is warranted.
Specifically, the analysis should consider a more direct nexus to the system, such as
substation design criteria.
Additionally, as detailed above, Attachment 1 should provide clarity regarding the
meaning of “applicable regulatory authorities.” Moreover, clarification is required
regarding the initial triggering factor for regulatory review.
Section III states that the regulatory review process is required before the footnote
can be utilized in “Year One” of the planning horizon. Does this mean that such
regulatory review only applies to year one or does it apply to year one and beyond?

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Question 4 Comment
If the former, NERC needs to provide a clear rationale for restricting such review
when limiting factors are already applied (i.e., voltages greater than 300 kV or a 25
MW minimum threshold value).

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. Other considerations can be a point of reference or sanity
check but in and of themselves are not sufficient for setting a threshold in this matter. The SDT believes that any deviation from the
threshold derived from the actual data may be viewed as a non-acceptable least common denominator approach and that no further
research is required. No change made.
The SDT believes that any attempt to more specifically enumerate regulatory bodies will result in the exact opposite effect of what is
stated in that inevitably there will be a one-off situation that doesn’t fit the statement. The SDT believes that the entity will know
who needs to be involved and will take the appropriate steps to make certain that the correct parties are involved. The only
mandated trigger for review is the need to have met the stipulations of the footnote and attachment prior to utilizing Load shed for
single Contingencies in a Corrective Action Plan in Year One. While the requirement is not mandatory until Year One, the SDT
believes that it would be a good practice to move forward as soon as an entity knows it is contemplating usage of the footnote. That
way, alternatives can be openly discussed before time becomes an overriding concern. No change made.
As stated, the review is only required prior to utilizing the footnote in a Corrective Action Plan in Year One. The SDT believes this
terminology is clear and understood. No change made.
Independent Electricity System
Operator

No

Consideration of Comments: Project 2010-11

No. The process presented in Section III is overly prescriptive and requires
information not necessary to the intended purpose.As state in Q1, we disagree with
prescribing a fixed MW threshold for Non-Consequential Load Loss in a continentwide standard, and propose alternate language as stated in Q1 comments.If this
section must deal with a review of the use of footnote ‘b’/’12’ to ensure that there
are no adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local support
for the use of Non-Consequential Load Loss under footnote ‘b’/’12’, only
information items 6 and 8 from section II are relevant for this assessment-the
remainder are not required for this section and should be deleted.
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Question 4 Comment
As stated in Q2 above, the use of footnote ‘b’/’12’ shouldn not be limited to the
Near-Term Planning Horizon. We propose that the words “in Year One of the
Planning Assesssment”be deleted.Items 1 and 2 complicate this section and are
unneccesary. They should be replaced by a phrase such as “for those planning
events where the use of footnote ‘b’/’12’ is referenced”.
We disagree with the need to submit to the ERO for a determination of whether
there are any adverse reliability impacts caused by the use of Non-Consequential
Load Loss. This will introduce a new type of review at the ERO that will create
uneccesary delays and burden, and is inconsistent with and not required for all of
the other performance requirements in the TPL standards. Submitting the analysis
to the adjacent Planning Coordinators and Tranmission Planners, and any functional
entity that requests it, as called for in requirement R8 of TPL001-2 should be
sufficient.

Response: Please see the response to question 1.
Please see the response to question 2.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. The SDT believes that Requirement R8 of
proposed TPL-001-2a is an important concept for sharing information and potentially resolving local differences, but it does not
necessarily provide the wider area view that the ERO could provide. No change made.
Midwest Independent
Transmission System Operator,
Inc.

No

No. MISO objects to a stakeholder process as outlined in Attachment 1. See our
comments under Question 5.

Response: Please see response to question 5.
Southwest Power Pool Reliability
Standards Development Team

No

Consideration of Comments: Project 2010-11

Section III is superfluous if the regulatory bodies are attending the open stakeholder
process. This section should be removed due to the fact that if there is an issue or
question on these events they should be addressed in the open stakeholder
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Question 4 Comment
meeting.
Not sure why the team decided to add the ERO as an entity to check after the
regulatory body has approved the use.
We feel like if there needs to bee coordination between affected entities that they
could participate in the open stakeholder process as well. You could add that they
include possible affected entities to the invite list of the open meeting to discuss
these footnote applications under section 1.

Response: The invitees to the stakeholder process should include all applicable entities and would be expected to include applicable
regulatory bodies as shown. However, there is existing protocol for relationships between functional entities and regulatory bodies
that goes beyond the extent of Section I and that is out of the purview of the SDT. That difference as well as the difference in Load
levels between Sections I and III is what drove the SDT to produce the draft as posted. No change made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. No change made.
The invitees to the stakeholder process should include all applicable entities and would be expected to include applicable regulatory
bodies as shown. However, there is existing protocol for relationships between functional entities and regulatory bodies that goes
beyond the extent of Section I and that is out of the purview of the SDT. That difference as well as the difference in Load levels
between Sections I and III is what drove the SDT to produce the draft as posted. No change made.
Western Area Power
Administration

No

See answer to Question 1.

Platte River Power Authority

No

See answer to Question 1.

Florida Municipal Power Agency

No

See FMPA Comments regarding the 75 MW threshold of Question 1.

Lakeland Electric
Gainesville Regional Utilities

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Question 4 Comment

Response: Please see response to question 1.
NBSO

No

See our comments under Q2 and Q3, above.

Response: Please see responses to questions 2 and 3.
Massachusetts Attorney General

No

The 75 MW and 25 MW limits do not belong there. It would be best if the limits
were established by stakeholder consensus and by state rulemakings.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a non-acceptable least common denominator approach. No change made.
National Grid

No

The current document includes the language: 2. The planned Non-Consequential
Load Loss under footnote 12 is greater than or equal to 25 MW.This gives no
concept of how long customers could expect to be out of service and hence
whether this would be an appropriate approach. Suggest using a value that is based
on energy, i.e., MWh. A value of 600MWh would represent 25 MW out for 24
hours, or could be 60 MW out for 10 hours, etc. This would seem to provide a more
valuable understanding the true impact to customers in assessing the health, safety
and welfare.
It is also expected that if Demand Resources are being used that they would be
excluded from the term “non-consequencial” load, and that the value being
discussed is only that in addition to any Demand Resources being used.

Response: The Section 1600 data request showed that entities were reporting footnote ‘b’ usage strictly in terms of MW. Therefore,
the SDT decided to stay with existing terminology in this regard. In addition, duration is one of the factors required in Section II so
the time element will be known to process participants. No change made.
Upon reviewing the comments, the SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be clarified

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Question 4 Comment

as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the
Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
Hydro One Networks Inc.

No

The process presented in Section III is overly prescriptive and duplicates information
not necessary for its intended purpose.As stated in Q1, we disagree with prescribing
a fixed MW threshold for Non-Consequential Load Loss in a continent-wide
standard, and propose alternate language in our response to Q1.If this section is
required to address a review of the use of footnote 12 to ensure that there are no
wide-spread adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local support
for the use of Non-Consequential Load Loss under footnote 12, only information
items 6 and 8 from section II are relevant for this assessment-the remainder are not
required for this section and should be deleted.
Items 1 and 2 complicate this section and are unneccesary. They should be replaced
by a phrase such as “for those planning events where the use of footnote 12 is
referenced.”
We disagree with the need to submit this information to the ERO for a
determination of whether there are any Adverse Reliability impacts caused by the
use of Non-Consequential Load Loss. This will introduce a new type of review at the
ERO that will create uneccesary delays and burden, and is inconsistent with (and not
required for) all of the other performance requirements in the TPL standards.
Submitting the analysis to the adjacent Planning Coordinators and Tranmission
Planners, and any functional entity that requests it, as called for in requirement R8
of TPL-001-2 should be sufficient.

Response: Please see the response to question 1.
Items 1 and 2 place the constraints in the process that separate the less restrictive procedure outlined in Section I from the more

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Question 4 Comment

restrictive procedure in Section III. The suggested change would require the same level of review for any use of the footnote. The
SDT does not believe that this is where the industry wants to go based on comments received. No change made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO is aware
of the proposed responsibility and has accepted this role if the industry approves. Therefore, the SDT believes that there will not be
any undue delays. The SDT believes that Requirement R8 of proposed TPL-001-2a is an important concept for sharing information
and potentially resolving local differences, but it does not necessarily provide the wider area view that the ERO could provide. No
change made.
Ameren

No

The responses to the data request indicate that 33% of the respondents that use
footnote “b” would drop 20 MW or less for single contingency events. Based on the
data, we believe that the threshold for reporting should be 20 MW instead of 25
MW.
As noted above in the response to item 1, we also believe that an upper limit of 40
MW should be established, again based on the responses to the data request.
We find this proposed stakeholder process unique because we are inviting retail
regulatory authorities to become involved in the compliance process for a handful
of utilities now, but potentially for more in the future. We are unaware of any other
standards where a state governmental agency is needed to grant permission for
utilities to utilize certain aspects of the standard. We believe that this proposed
process would potentially set a bad precedent, is not good policy for either the
regulators or the transmission planners, and does not belong in a NERC standard.

Response: The SDT believes that the threshold selected is consistent with the data supplied in the data request within reasonable
limits. No change made.
Please see response to question 1.
The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. While formal
approval may not be provided by some regulatory bodies as pointed out in other comments, Section III does not require formal
approval but rather a lack of dissent. No change made.

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Arizona Public Service Company

No

Question 4 Comment
The threshold of 25 MW in item 2 of section III is too low. It should be same as the
maximum allowed value in foot note b.
In addition, AZPS does not agree that no objection assurance by the Regional Entity
should be required. Once the process has been fully vetted by the stakeholders,
including the regulatory authority for retail service, there is absolutely no need for
Regional Entity involvement. There would be no adverse affect of nonconsequential load tripping on the BES. Hence no reason for Regional Entity
involvement is needed.

Response: The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of
footnote ‘b’ by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for
the amount of Load that could be planned to be shed under footnote ‘b’. The SDT believes that any deviation from the threshold
derived from the actual data may be viewed as a least common denominator approach and would thus be rejected. No change
made.
The remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was proposed. The ERO has
been proposed as the best choice to provide such oversight. No change made.
Manitoba Hydro

No

The word ‘assure’ should be ‘ensure’ in the opening paragraph of III. Instances for
which Regulatory Review of Non-Consequential Load Loss under Footnote 12 is
Required.

Response: The SDT agrees and has made the change suggested.
Section III, first paragraph: Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning Coordinator must assure ensure that
the applicable regulatory authority authorities or governing bodybodies responsible for retail electric service issues does not
object to the use of Firm Demand interruption under footnote ‘b’ if either:
ISO New England

No

Consideration of Comments: Project 2010-11

This provision violates both the federal and state jurisdictional split over
transmission facilities, and would violate several FERC orders directing the

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Question 4 Comment
independence of RTOs in the regional system planning process. Said another way,
the determinations of a federal transmission planning entity may not be required
through an ERO standard to be subject to non-jurisdictional review and approval by
state entities. Further, the provision violates Section 215 of the Federal Power Act,
as the ERO cannot require the review of a particular transmission system plan by
state entities. The following language should therefore be deleted from Section III
of Attachment 1: “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 assure that the
applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the use of Non-Consequential Load Loss under
footnote 12... .”
Overall, the order of Section III is also notable. During year, two through ten of the
overall planning horizon the standard allows for Non-Consequential Load Loss
without state approval. In the first year of the assessment, approval becomes
required for Non-Consequential Load Loss. In year one, even if mandating state
participation and decisional authority in a federal planning process was legally
permissible, it is too late to allow for any other alternative as transmission planning,
siting and construction of non-load loss alternatives would not be completed in the
needed period. If there were non-load loss alternatives available, the use of nonconsequential load loss would not be necessary, but it would also not be part of a
transmission plan. The Regional Entities with NERC oversight perform periodic
audits and require self-certification of the planning process. By virtue of the audit
and self-certification process, NERC has the ability to monitor the use of NonConsequential Load Loss in planning assessments.
In addition to being notable for the year one timing, Section III seems incomplete.
In the case where there is objection to Non-Consequential Load Shedding, the
process appears to end without resolution. The submission to the ERO “for a
determination of whether there are any Adverse Reliability Impacts caused by the
request to utilize footnote 12 for Non-Consequential Load Loss” conflcts with

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Question 4 Comment
federal law and orders of the Federal Energy Regulatory Commission. As noted
above, the ERO is not a planning entity and does not have authority to displace the
reliability planning performed by planning entities. Transmission planning entities
are those directed by FERC to make the determinations regarding adverse reliability
impacts. If any entity wishes to challenge those determinations, it may do so before
FERC under Section 215 of the Federal Power Act. Further, this provision would
conflict with orders of the FERC regarding the independence of RTOs to conduct the
regional transmission planning process. A reliability standard may not change the
scope or meaning of federal statutes nor may it contradict or collaterally attack
orders of the Federal Energy Regulatory Commission. For these reasons, this
provision should be removed from the attachment to the proposed standard.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. The
SDT does not believe that the footnote violates any regulations concerning transmission planning. The proposed process simply
brings stakeholders including local regulators to the table in an open and transparent manner. No change made.
While the requirement is not mandatory for use in a Corrective Action Plan until Year One, the SDT believes that it would be a good
practice to move forward as soon as an entity knows it is contemplating usage of the footnote. And nothing in the document
precludes such action. Since the applicable regulator would be at the table and would therefore see potential uses of the footnote
prior to Year One, the stakeholder process provides the opportunity to get any potential timing issues out before they become a
impediment. Furthermore, the remand Order made it clear that oversight was required for instances where use of footnote ‘b’ was
proposed. This would imply that FERC does not believe that audit and self-certification is sufficient in this matter. No change made.
The ERO is not participating in the planning process. The role of the ERO is restricted to a determination of whether the planned
utilization of footnote ‘b’ will cause an Adverse Reliability Impact to the BES. The ERO has no further role in the transmission
planning process beyond that determination. No change made.
TVA Transmission Reliability
Engineering and Controls

No

TVA believes that the requirements of 25 MW as well as any Bulk contingency over
300-kV is much too burdensome. TVA believes that only larger load drops (such as
50 MW and above) should require ERO review.

Response: The SDT believes that the threshold selected is consistent with the data supplied in the data request. Increasing the

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Question 4 Comment

threshold to 50 MW is not consistent with the data supplied and the SDT believes that such an action would be viewed as a nonacceptable least common denominator approach. No change made.
Iberdrola USA

No

Why would a retail service regulator approve a 300 kV and above performance
issue?

Response: The voltage level is not the significant issue; the significant issue is making certain that the regulator understands that the
transmission plan is to shed Load for a single Contingency so that they can understand the implications of the proposed actions and
properly evaluate other available alternatives.
LCRA Transmission Service
Corporation

No

NB Power Transmission

No

Response: Without specific comments, the SDT is unable to respond.
Texas Reliability Entity

Yes

1. TRE requests clarification whether the 25 MW limit of Non-consequential Load
Loss (Section III (2)) applies to a single contingency event for a specific Transmission
Planner’s region or to the entire Planning Coordinator area. For example, if a single
contingency requires multiple Transmisson Planners to shed load, is each
Transmission Planner allowed to drop up to 25 MW of load before requiring
regulatory review? Or did the SDT intend to require the Transmission
Planners/Planning Coordinator to submit the plan for regulatory review if the total
load shed for the single contingency equals or exceeds 25 MW?
2. TRE feels that the requirement in Section III that the Planning Coordinator or
Transmission Planner must submit information to the ERO for a determination of
whether there are “any Adverse Reliability Impacts” is overly burdensome to
industry, assuming that this refers to the new definition of “Adverse Reliability
Impact” (limited to Instability and Cascading). It is extremely unlikely that any such
impacts will result from application of this footnote, and any that might occur will

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Question 4 Comment
be identified in the stakeholder process. If the ERO determination step is retained,
then a timeline should be included for completion of the ERO determination
process.

Response: The footnote is written on a single Contingency basis so the latter instance of the comment is correct – the plan should be
submitted if the total Load shed is greater than or equal to 25 MW.
Such a determination may be considered unlikely but the SDT believes that the remand Order made it clear that oversight was
required for instances where use of footnote ‘b’ was proposed. The ERO is aware of the proposed responsibility and has accepted
this role if the industry approves. Therefore, the SDT does not believe that a timeline is required. No change made.
California Independent System
Operator

Yes

Despite a public consultation process that includes the regulator(s), the standard
then calls for notification to the regulator(s) and only moving forward once the
regulator indicates that it does not oppose the shedding of load (“once assurance
has been received that...”). This is still requiring the regulator to do something, and
could be problematic if no response is provided by the regulator. How would one
address silence on the part of the regulator?

Response: The SDT believes that Sections I and III represent two separate and distinct instances of the process. In Section I, the
regulator is just one of perhaps many interested and applicable parties. However, in Section III, where larger values of Load are
involved, there is a more formal role for regulators to play. Each local situation is unique – in some there may be formal approval
provided, in others just a lack of dissent. If the regulator is silent on the proposal, the entity can move forward with the plan. No
change made.
Lincoln Electric System

Yes

Consideration of Comments: Project 2010-11

While supportive of Section III, LES believes the language in the last paragraph could
be further enhanced with the following changes [located in brackets] to ensure a
complete and accurate record is provided to the ERO."Once [written] assurance has
been received that the applicable regulatory authority or governing body
responsible for retail electric service issues does not object to the use of NonConsequential Load Loss under footnote 'b', the Planning Coordinator or
Transmission Planner must submit the [written assurance and] information outlined

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Question 4 Comment
in items II.1 through II.8 above to the ERO...”.

Response: The SDT does not believe it is appropriate to add ‘written assurance’ as the requirement only involves lack of dissent. No
change made.
Duke Energy

Yes

SERC EC Planning Standards
Subcommittee

Yes

Associated Electric Cooperative
Southern Company

Yes

American Electric Power

Yes

Seminole Electric Cooperative,
Inc.

Yes

Deseret Generation &
Transmission

Yes

American Transmission Company

Yes

Public Service Company of New
Mexico

Yes

Idaho Power Company

Yes

SCE&G

Yes

Georgia Transmission Corp

Yes

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Yes or No

Question 4 Comment

Response: Thank you for your support.

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5.

If you have any other comments on this Standard that you haven’t already mentioned above, please provide them here:

Summary Consideration: The comments supplied for question 5 are basically repetitive of what was stated for previous questions.
Responses are provided consistent to what was stated above.
The following changes have been made due to industry comments:
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be
interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2)
Interruptible Demand or Demand-Side Management Load.
Organization

Question 5 Comment

Independent Electricity System
Operator

(1) We’d like to reiterate our support for allowing load interruption for a singlecontingency
with sufficient review/oversight and under acceptable conditions, including no adverse impact on
the reliability of the interconnected bulk power system. The reliability aspects (BES performance
requirements) should be reviewed for acceptability by the adjacent Planning Coordinators and
Transmission Planners. However, issues pertaining to economics or externalities which may not be
directly reliability-related are always available for review and debate by the stakeholders via the
regulatory processes and subject to approval by the regulatory authority of each jurisdiction
(including those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2 approved by NERC
BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the application of
footnote ‘b’/’12’ that is allowed for the P1 events. Events in P2, P4, and P5 can involve more
elements and can be more onerous and stressful to the system than the P1 events, and if use of
footnote ‘b’/’12’ is permitted in the less stressful P1 events, it should also be permitted in P2, P4
and P5 events.
(3) We suggest that NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve it. Accordingly, we believe that the focus of
footnote ‘b’, and footnote 12 should be that interruption of load must not have an adverse impact
on the reliability of the interconnected bulk power system. A continent-wide standard should
not concern itself with the reliability of supply or supply continuity for local load, as that is the

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Question 5 Comment
responsibility of the applicable regulatory authority or its agencies responsible for local
transmission and retail service over the load to be curtailed.As mentioned above, NERC Standards
and their requirements should focus on what is the anticipated outcome rather than how to
achieve it. In this regard, we believe that Attachment 1 is not necessary because it prescribes a
process which goes beyond the outcome of the standard and dictates how stakeholdering must be
carried out. The individual jurisdiction should establish the process for ensuring compliance with
the standard and decide to what extent a stakeholdering process is necessary to establish the
acceptable level of load rejection for the area in a manner consistent with local transmission
established service levels.

Hydro One Networks Inc.

(1) We’d like to reiterate our support for allowing load interruption for a single contingency with
sufficient review/oversight and under acceptable conditions, including no adverse impact on the
reliability of the bulk electric system. The reliability aspects (BES performance requirements)
should be reviewed for acceptability by the adjacent Planning Coordinators and Transmission
Planners. However, issues pertaining to economics or externalities which may not be directly
reliability-related are always available for review and debate by the stakeholders via the
regulatory processes and subject to approval by the regulatory authority of each jurisdiction
(particularly those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-2a (previous TPL-001-2 approved by the NERC
BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the application of
footnote 12 that is allowed for the P1 events. If a load is allowed to be interrupted for a single EHV
transmission line contingency (Category P1), it should be allowed to interrupt the same load if the
primary breaker fails (the event becomes category P4) and the fault is cleared by other breakers.
Similarly, if the same breaker has an internal fault or there is a fault on the same bus section
(Category P2) or there is a failure of a relay (Category P5), which results in the loss of the same
EHV transmission line, it should be allowed to interrupt the same load. Events in P2, P4, and P5
can involve more elements and can be more onerouse and stressful to the system than the P1
events, and if use of footnote 12 is permitted in the less stressful P1 events, it must also be
permitted in P2, P4 and P5 events. This issue has been raised by many entities in previous
occasions and we believe the STD has not provided a convincing response.

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(3) We suggest that NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve them. Accordingly, we believe that the focus of
foot note ‘b’, and footnote 12 should be that interruption of load must not have a widespread,
adverse impact on the reliability of the interconnected BES. A continent-wide reliability standard
should not concern itself with the reliability of supply or supply continuity for local load, as that is
the responsibility of the applicable regulatory authority or its agencies responsible for local
transmission and retail service over the load to be curtailed. If NERC and/or FERC believe that MW
threshold needs to be addressed within NERC Standard for US registered entities then the
standard must clearly state that the requirement is for US registered entities only.

Response: (1) Thank you for your support.
(2) Such discussion is out of scope for this project since TPL-001-2 has been approved by the industry through the standards
development process and by the NERC Board of Trustees. Nothing in this project affects where footnote 12 is applied within Table 1.
The only change being proposed is to the details of how to utilize footnote 12 as shown in the proposed Attachment 1. No change
made.
(3) FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well defined, did
not include quantitative and qualitative criteria for allowing curtailment of Firm Demand, and did not assure that BES reliability
would be maintained. The balloted draft added detail and specificity to the already approved approach. Canadian entities are
allowed to adopt ERO Reliability Standards, reject them outright, or adapt them for their own use within the confines of provincial
regulations. Nothing has changed in that regard with this proposed standard. No change made.
Manitoba Hydro

(1) Effective Date section 5: The language used in the revision that was made is fine, however,
where the language has been placed in the section is confusing. The language has been added to
the end of the sentence that starts ‘in those jurisdictions where regulatory approval is not
required’ and lumped those two concepts together. In our mind, there should be 3 separate
concepts 1) where regulatory approval required 2) where regulatory approval not required and 3)
as may otherwise be approved by applicable laws.
(2) Corresponding changes do not appear to have been made, TPL 1 and TPL 2 are not consistent
in terms of the language used in the Effective Date section or the Attachment 1 (the sections to

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which changes were made since last circulation).

Response: (1) The language used in the effective date section is provided by NERC Legal and was designed to take into account the
situations raised in the comment. No change made.
(2) The SDT wishes to point out that the language may be slightly different due to the specific circumstances regarding definitions,
etc., in the timeframe relevant to the two standards. However, the SDT believes that the language used in the two standards is
consistent. Without specific references the SDT is unable to respond further. No change made.
ACES Power Marketing
Standards Collaborators

(1) The SDT needs to consider the connection between the developing standards to maintain and
improve reliability with the costs required to meet those standards. We believe there is an
imbalance of the costs associated with meeting compliance for the current draft standard with
proposed benefit of maintaining reliability of the BPS. This standard is a good candidate for the
CEAP initiative to determine the cost benefits of reliability.
(2) The standard needs to allow more flexibility regarding the use of planned load shed to address
transmission performance issues in the planning horizon. It needs to recognize that these planned
load shedding events may only be preliminary decisions for addressing problems that are several
years away. If there is little chance that the planned shed load will ever be relied upon in the
operating time horizon, there should be much less stringent requirements. For instance, if a PC or
TP relies on planned load shed for year five of the planning horizon but year one does not utilize
the planned load shed, they have four years to develop another solution. Why should an entity
expend great effort and resources for year five when another solution will likely be developed
within that time period?
(3) What does “materially changed” mean and what degree of a change would be considered
material in the Attachment 1 stakeholder process? The SDT should clarify specific conditions in
Section II that would constitute a material change.
(4) Thank you for the opportunity to comment.

Response: (1) Cost factors are one of the elements in the list of criteria in Section II. Costs of different alternatives will be part of the
information provided and rationales for selection or non-selection of alternatives should include consideration of costs. The CEAP

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initiative is still a work in progress and will not be ready for use in the timeframe of this project. No change made.
(2) The SDT agrees that more flexibility is needed in the longer term; therefore, in the Long-Term Transmission Planning Horizon the
stakeholder process is not required, and its use is limited to the Near-Term Transmission Planning Horizon. However, the SDT
believes that it is appropriate for planners to share future information in Section II so stakeholders are aware of any potential Load
shed. No change made.
(3) The SDT believes that the planning entity has the best understanding of when a change would become material. With the large
range of design philosophies and geographic difference between the entities within NERC, it is not practical to adopt a single one size
fits all approach. In addition, since the use of footnote ‘b’ will be a part of the entity’s Corrective Action Plans, interested
stakeholders will have the opportunity to question the continued use of footnote ‘b’. No change made.
Sacramento Municipal Utility
District

1) The decision of necessary infrastructure addition versus a determination of load shed in lieu of
costly transmission should be determined at the Public Utility Commission or Local Board of
Directors not through a laod level limitation.
2) There are no impacts to the BES for load shedding actions where it is determined that it is
confined to a set boundaryand demonstrate to not lead to cascading, uncrontrolled separation or
blackout.
3) Where a concern that a stakeholder process be "gamed" to allow the unscrupulous entity to
claim notification of affected stakeholders was followed should not dictate a continent-wide
standard direction for other stakeholders.

Response: 1) FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
2) The use of Footnote ‘b’ as proposed provides assurance that there is no Adverse Reliability Impact. No change made.
3) The conditions placed on the stakeholder process will provide consistency in the application of footnote ‘b’ on a continent-wide
basis. No change made.
Tri-State G&T

1. It is not clear how transmission projects with long lead times (such as T-lines) would be handled

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by “Footnote b”. In other words, it is not clear if it is acceptable for a TP to plan for shedding Firm
Demand in the Near Term Planning Horizon without meeting the conditions shown in “Attachment
1” when a mitigating project is planned that cannot be constructed in the Near Term Planning
Horizon.
2. NERC Functional Model definitions for Planning Authorities and Transmission Planners do not
include the types of activities being proposed in “Attachment 1.” As written, this standard
mandates functions on functional entities that are outside those defined by the NERC Functional
Model.
3. In the NERC Glossary of Terms, Interruptible Demand is defined as “Demand that the end-use
customer makes available to its Load-Serving Entity via contract or agreement for curtailment.”
The process described in Attachment 1 creates an agreement between stakeholders (aka “end-use
customers”) and their transmission providers for shedding Demand. Thus, if the process described
in Attachment 1 is followed, the “Firm Demand” referenced in “Footnote b” would be reclassified
as “Interruptible Demand.” In essence, Firm Demand would not be interrupted. If this was the
intention of FERC, NERC, and the Drafting Team, the standard should just state “Interruption of
Firm Demand is not allowed.”
4. It is not clear how section III of “Attachment 1” would be applied to entities that only deliver
wholesale electric service and not retail electric service.

Response: 1. Any instance of proposed Load shed for a single Contingency situation in a Planning Assessment must meet the
conditions of footnote ‘b’. No change made.
2. The NERC Functional Model is a guideline for activities required of cited functional entities. It is periodically updated as conditions
change. While the activities mentioned in the standard may not be explicitly spelled out in the NERC Functional Model, the SDT does
not believe that they are out of scope for either a Planning Coordinator or a Transmission Planner. No change made.
3. Upon reviewing the comments, the SDT has seen that Demand that is not included as Firm Demand for footnote ‘b’ could be
clarified as shown below.
TPL-002-1c: footnote b) - It is recognized that Firm For purposes of this footnote, the following are not counted as Firm
Demand will be interrupted if it is: (1) Demand directly served by the Elements removed from service as a result of the

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Contingency, orand (2) Interruptible Demand or Demand-Side Management Load.
4. The SDT believes that the wholesale customer will be one of the stakeholders included in the process and any use of the footnote
must go through the stakeholder process. No change made.
MRO NSRF
USACE
MidAmerican Energy Company

Minnkota Power Cooperative
Otter Tail Power Company

1. In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption” or “NonConsequential Load Loss” be initiated by a manual event such as operator action or does it need to
be automatic? RECOMMENDATION: In TPL-002-1c Table I footnote ‘b’ add a sentence stating
“Acceptable methods to enact Firm Demand Interruption may include manual or automatic
processes that can be initiated within a reasonable timeframe”
1. MPC QUESTION: In TPL-002-1c Table I and TPL-001-2a Table 1 can “Firm Demand interruption”
or “Non-Consequential Load Loss” be initiated by a manual event, such as operator action, or does
it need to be automatic, such as Under Voltage Load Shedding? a. RECOMMENDATION: In TPL002-1c Table I footnote ‘b’, add a sentence stating “Acceptable methods to enact Firm Demand
Interruption may include manual or automatic processes that can be initiated within a reasonable
timeframe”

Response: Whether an action is automatic or manual is of no concern with regard to footnote ‘b’ as long as manual actions are
executable within the time duration applicable to the Facility Ratings. No change made.
California Independent System
Operator

A concern with the new TPL-001-2 standard is what we see as being the elimination of the existing
footnote c, the footnote that qualified Category C load shedding as “may be necessary”. The
wording under the new TPL-001-2 appears that load shedding is the unqualified expectation of the
criteria for C contingencies.

Response: The SDT clarified the expectations for the former Category ‘C’ Contingencies when it developed proposed TPL-001-2. TPL001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees. Nothing in this
project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how to utilize
footnote 12 as shown in the proposed Attachment 1. Any discussions concerning the application of the footnote within the
performance table are therefore out of scope for this project. No change made.

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Iberdrola USA

A one-paragraph footnote encompassing a 2-page attachment is cumbersome for a Reliability
Standard.

Response: The SDT made every effort to make the revisions required to be as simple as possible while meeting the requirements of
the remand Order. No change made.
BC Hydro and Power Authority

BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c - System
Performance Following Loss of a Single BES Element (footnote b) and TPL-001-2a - Transmission
System Planning Performance Requirements (footnote 12). BC Hydro votes YES in support of this
ballot and wishes to provide the following two comments:1.At this time BC Hydro has concerns
about the level of stakeholder consultation that might be required as a result of the
implementation of this standard and will bring this concern to the attention of our regulator if
necessary.
2.At this time BC Hydro has concerns about the instances for which regulatory review of nonconsequential load loss under footnote 12 is required and will discuss those with our regulator if
necessary.

Response: 1. and 2. The SDT understands your situation and comment and appreciates your overall support.
Hydro Québec TransÉnergie

Even if the SDT said it is not in its scope, the following difficulty with the application of note 12
needs to be addressed by NERC. There are no limit on non-consequential load loss for Single
Contingency P2-2. and P2-3. (HV only), multiple Contingencies P4 and P5 (HV only), and P6 and P7.
The note 12 allows limited non-consequential load loss for single contingency P1, Multiple
Contingency P3. Non-consequential load loss is not allowed for P2-2 and P2-3. (EHV), and P4 and
P5 (EHV). Considering the EHV Facilities, it is not reasonable to accept some non-consequential
load loss for single contingency P1 and P2-3, and then deny it for Multiple Contingency categories
P4 and P5 which are statistically less frequent than the former. Also, the Multiple Contingency P7
(for which there is no limit on non-consequential load loss) is more frequent than P2-3, P4 and P5.
This technical irregularity must be reviewed and addressed.

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Question 5 Comment

Northeast Power Coordinating
Council

There are no limits on non-consequential load loss for Single Contingency P2-2 and P2-3 (HV only),
multiple Contingencies P4 and P5 (HV only), and P6 and P7. Footnote 12 allows limited nonconsequential load loss for single contingency P1, Multiple Contingency P3. Non-consequential
load loss is not allowed for P2-2 and P2-3 (EHV), and P4 and P5 (EHV). Considering the EHV
Facilities, it is not reasonable to accept some non-consequential load loss for single contingency
P1 and P2-3, and then deny it for Multiple Contingency categories P4 and P5 which are statistically
less frequent than the former. Also, the Multiple Contingency P7 (for which there is no limit on
non-consequential load loss) is more frequent than P2-3, P4 and P5. This technical irregularity
must be reviewed and addressed.

Response: TPL-001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees.
Nothing in this project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how
to utilize footnote 12 as shown in the proposed Attachment 1. No change made.
Southern California Edison
Company

Footnote “b”/Footnote 12 as currently written does not provide for an exemption to allow for the
use of Firm Demand interruption as a short-term solution to transmission problems. Many entities
would benefit from being allowed to use Footnote “b”/Footnote 12 as a temporary solution in
response to construction delays until facilities to mitigate an N-1 contingency identified in a
Planning Assessment can be installed. Under the current proposal, the stakeholder process will
provide very little value in attempting to resolve such a problem. In fact, the current Footnote
“b”/Footnote 12 could result in a stakeholder process that may actually slow the implementation
of mitigation measures for the system.

Response: The SDT does not agree that the footnote does not provide for the use of Firm Demand interruption as a short-term
solution to transmission problems. That has always been the point of the footnote and nothing in this project has changed that
intent. The only changes are to the method in which the footnote is invoked. No change made.
ISO New England

In summary, the main footnote is unobjectionable, but this standard as proposed has misplaced
jurisdictional authority under Section 215 of the Federal Power Act for both states and the ERO
through several of the process points and conditions set out in the attachment to the stardard.
The removal of references is required for the standard to comport with the law. These revisions to

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the standard can be made, which would then allow the draft standard to comply with FERC’s
further guidance and the other legal limitations described above.

Response: The SDT believes that the role provided to regulatory bodies is consistent with current practices in the industry today. The
SDT does not believe that the footnote violates any regulations concerning transmission planning. The proposed process simply
brings stakeholders including local regulators to the table in an open and transparent manner while setting criteria for when footnote
‘b’ can potentially be utilized. The ERO is not participating in the planning process. The role of the ERO is restricted to a
determination of whether the planned utilization of footnote ‘b’ will cause an Adverse Reliability Impact to the BES. The ERO has no
further role in the transmission planning process beyond that determination. No change made.
Ameren

It might be helpful to probe further with the respondents who have no planned upgrades
identified to address the dropping of non-consequential load to see what relevant system
upgrades might entail, and the estimated costs associated with such upgrades, to address such
situations.

Response: The SDT used the Section 1600 data request process to the best of its ability within the limited timeframe afforded to this
project. No change made.
LCRA Transmission Service
Corporation

LCRA TSC disagrees with the October 2012 revision of TPL Table 1 Steady State & Stability
Performance Footnotes (TPL-002-1c, footnote ‘b’ and TPL-001-2a footnote 12). The proposed
stakeholder process required to be conducted during each Planning Assessment is overly
burdensome. Further, it is not clear from the proposed process that a key concern expressed by
the Commission with respect to use of Firm Demand load shedding is addressed - Notice to Firm
Demand Customers.
In addition, the proposed stakeholder process introduces several questions that need to be further
clarified. For example:
1) Who defines the processes and procedures to be used?
2) Who is/are the decision maker(s)?
3) Who determines if the processes and procedures were followed?

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4) Who carries out the administrative tasks (such as notice, securing meeting space,....)?
5) Who can participate? Does someone need to demonstrate a material interest in order to
participate?
6) What are the means of participation (accepted forms of communication, timelines...)?
7) What are the criteria for decision-making?
8) What is the process for dispute resolution?
How would does an Attachment become part of a NERC Standard? Should Attachment 1 be a
requirement?
In addition, support is needed for the bright-line 25 MW level.
Lastly, the statement, “Before a Firm Demand interruption under footnote ‘b’ is allowed to be
utilized as an element of a Corrective Action Plan in Year One of the Planning Assessment,” implies
that Firm Demand interruption may be used for years two through five of the Planning Assessment
without the stakeholder process.

Response: Stakeholders representing the interests of Firm Demand customers would certainly be among the parties involved in
Section I of the stakeholder process. No change made.
1) through 8) There is not a one-size-fits-all response to these questions for a continent-wide standard. The SDT provided the key
components of an open and transparent stakeholder process while allowing variations that may be required due to differing structures
and frameworks across the continent. Therefore, the answers to these questions may be different for each individual stakeholder
process.
Attachments have been used in the past in other standards and are an accepted part of a standard.
The remand order from FERC requested that a Section 1600 data request be made to provide data on the actual usage of footnote ‘b’
by planners. This data was then to be utilized by the SDT as part of its consideration in arriving at a maximum value for the amount of
Load that could be planned to be shed under footnote ‘b’. The 25 MW threshold was directly derived from this data. The SDT believes
that any deviation from the threshold derived from the actual data may be viewed as a non-acceptable least common denominator
approach. No change made.

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The SDT disagrees with the statement made by the commenter. Firm Demand interruption must go through the process for any year
in the Near-Term Transmission Planning Horizon as is clearly stated in the main body of the footnote. No change made.
TVA Transmission Reliability
Engineering and Controls

Please see responses to question #2,3, and 4. TVA believes that only load drops of higher
magnitudes go thru the Stakeholder and regulatory review.

Response: Please see responses to questions 2, 3, and 4.
Public Utility District No.1 of
Snohomish County
MEAG Power
City of Austin
Clark Public Utilities

Public Utility District No.1 of Snohomish County generally disagrees with the October 2012
revision of TPL Table 1 Steady State & Stability Performance Footnotes (Planning Events and
Extreme Events). “Footnote b) An objective of the planning process is to minimize the likelihood
and magnitude of interruption of firm transfers or Firm Demand following Contingency events.
Curtailment of firm transfers is allowed 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 the shedding of any Firm Demand. It is recognized that Firm
Demand will be interrupted if it is: (1) directly served by the Elements removed from service as a
result of the Contingency, or (2) Interruptible Demand or Demand-Side Management Load. In
limited circumstances, Firm Demand may be interrupted throughout the planning horizon to
ensure that BES performance requirements are met. However, when interruption of Firm Demand
is utilized within the Near-Term Transmission Planning Horizon to address BES performance
requirements, such interruption is limited to circumstances where the use of Firm Demand
interruption meets the conditions shown in Attachment 1. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW.””Footnote 12. An objective of the
planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency 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 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.”

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The proposed revisions require that a Transmission Planner or Planning Coordinator provide
assurance that the applicable regulatory authority or governing body responsible for retail electric
service issues does not object to the interruptions of firm demand under TPL-002 footnote ‘b’ or
TPL-001 footnote ‘12’ if the voltage level of the contingency is greater than 300 kV with certain
sub-conditions or if the planned interruption of firm demand under these footnotes is greater than
25 MVA. In addition, under no case can planned Non-Consequential Load Loss exceed 75 MW.The
magnitude and duration of load loss is a Level of Service (“LOS”) or Customer Service issue that is
the jurisdiction of Public Utility Commissions and Local Electric Utility and Municipality boards.
The boards and commissions represent their customers which often have diverse service and rate
expectations that often are a result of local industry requirements, geography, urban/rural
characteristics, and other factors of the particular service territory. Boards and commissions hold
public meetings seeking input on various utility matters that often address services and rates. The
rate impacts for customers are important; often more important than the service levels depending
on the particular customer or customer class. Local boards and commissions are very close to
these issues and weigh the input provided through public testimony to best represent their
customer needs over the region they represent and have jurisdiction under state and local codes
to address.The 75 MW Non-Consequential Load Loss threshold and the required NERC process do
not resolve or address a reliability issue. The TPL footnotes address service requirements and
should not be part of a NERC Reliability Standard any more than mandating specific System
Average Interruption Frequency Index ("SAIFI") and System Average Interruption Duration Index
("SAIDI"). The Non-Consequential Load Loss requirement is an economic driven threshold that is
not consistent throughout North America due to diverse customer needs and expectations. For
instance, in some areas it may make economic sense and receive local approval to fund a $100
million system reinforcement to mitigate 1 in 20 year (5 percent chance of occurring) 76 MW NonConsequential Load Loss exposure. However there are many communities that could not justify or
support multi-million facilities to mitigate a 1 in 20 year event that may cause the NonConsequential Load Loss of 76 MW of load. Public Utility District No.1 of Snohomish County
supports removing the Non-Consequential Load Loss thresholds from the TPL Reliability Standards
and allow the local boards and commissions to continue to address Customer Service Level issues
as they are closest to the customers’ needs and have jurisdiction over this issue.

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Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted
draft added detail and specificity to the already approved approach. The proposed standards include the local regulatory bodies at
every step in the process. This will allow those bodies to have input at every step. The SDT believes that the proposed changes to
the standards are in alignment with the charge that was given to it. No change made.
Xcel Energy

Setting limits on the amount of NCLL only sets the stage for failure in the compliance of NERC
standards and fails to take note of what is really the issue; the planning of a transmission system
that is both reliable and economically viable for all stakeholders and customers. It should be
emphasized that the use NCLL in a “planning process” is only assuming the conditions set in the
study will exist and in no way reflects the conditions seen during the day to day operation of the
transmission system.
Xcel Energy is concerned about the previous ability on loss of load in anticipation of the next
outage (previously C3 now P6). For TPL-003, loss of load in anticipation of the next system outage
was covered under footnote B. Footnote 9 now states, “...the re-dispatch does not result in any
Non-Consequential Load Loss. “ This is a large increase in requirements of the transmission
system to operate. As written, it appears that footnote 12 is NOT applicable to P6 contingencies.
Please clarify is this is the intent.

Response: The SDT does not believe that it needs to add language emphasizing that there is a difference between planning and
operations when these standards are clearly planning standards. No change made.
The SDT disagrees that there was a previous ability to shed Load in anticipation of the next Contingency. Footnote ‘b’ only allowed
curtailment of firm transfers in preparation for the next Contingency. In addition, footnote 12 is not applicable for P6 planning
events since Non-Consequential Load loss is allowed. No change made.
Arizona Public Service Company

The following comment relates to Table 1. It is not clear why footnote 12 applies only to P2-1. The
events P2-2, P2-3, P4, P5 are much less probable and the footnote 12 should be applicable to all
these events. Why is that loss of non-consequential load is allowed for line tripping without fault
but not for a bus fault which is much less likely and could result into same line trip. Similar

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arguments apply to other scenarios listed above.

Response: TPL-001-2 was approved by the industry through the standards development process and by the NERC Board of Trustees.
Nothing in this project affects where footnote 12 is applied within Table 1. The only change being proposed is to the details of how
to utilize footnote 12 as shown in the proposed Attachment 1. Any discussions concerning the application of the footnote within the
performance table are therefore out of scope for this project. No change made.
Electric Reliability Council of
Texas, Inc.

The SDT is not required to utilize the stakeholder approach by Order 762 or any other relevant
FERC orders. FERC merely provided guidance as to how the rejected proposal could be improved.
However, if the SDT elects to pursue an exception process, such exceptions should be based on
objective criteria, and the process should be external to the NERC Reliability Standards (e.g. in the
Rules of Procedure).In Order 693, FERC directed NERC to clarify footnote (b) to prohibit shedding
firm load except for consequential load loss (Order 693 at PP 1773, 1794 and 1797}. In a related
compliance order, FERC reaffirmed its position. (130 FERC 61,200 (March 18, 2010) at PP 8-10
(Compliance Order)) In a subsequent order, FERC clarified that its Order 693 directive did not
preclude consideration of specific comments related to planning the system based on load
shedding at the “fringes" of a system. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification
Order)) FERC held that regional variances for case-specific circumstances or a case-specific
exception process to plan for the loss of firm service “at the fringes of various systems" would be
acceptable. (131 FERC 61,231 (June 11, 2010) at P 21 (Clarification Order)) However, FERC also
stated that it viewed the basis for such exceptions as economic, not reliability, with the
justification being that it was not economic to invest in the bulk electric system to serve all nonconsequential load customers under some single contingency conditions. (Order 693 at P 1792)
FERC made clear that any such regional differences or case specific exception processes cannot
reflect the lowest common denominator, and, they must be technically justified, and such
justification must be strong. (Clarification Order at P 21, See also Order 693 at P 1794) This is
consistent with FERC's position that this is a matter of "fundamental issue of transmission service".
(Order 693 at P 1793) In recognizing that meeting firm demand under single contingency
conditions is fundamental to transmission service, FERC noted that NERC's definition of firm
transmission service is the "highest quality (priority) service offered to customers ... that
anticipates no planned interruption." (Order 693 at P 1793)Against this background, NERC filed

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revisions to footnote b that allowed transmission plans to shed non-consequential load under
single contingency conditions, provided appropriate process applied to such planning
determinations/outcomes. In Order No. 762, {139 FERC 11 61,060 (April 19, 2012)) FERC rejected
the approach proposed by NERC and provided guidance on acceptable approaches to footnote b.
However, FERC did not endorse or mandate any particular approach. Rather, it merely urged
"NERC to develop in a timely manner an appropriate modification that is responsive to the
Commission's directives in Order No. 693 and our concerns set forth in this Final Rule." (Order 762
at P21) FERC stated that in order for any such proposal to have merit, it must be technically
justified and must not reflect the lowest common denominator.As discussed, the proposed
stakeholder approach is not appropriate for NERC Reliability Standards. The SDT should abandon
that approach and consider simple revisions to footnote b that reference a case by case exception
process based on objective criteria that is external to the NERC Reliability Standards (e.g. Rules of
Procedure). Alternatively, it should develop revisions to the continent-wide standards that clarify
that non-consequential load shedding is not generally permitted for single contingency conditions,
but, consistent with FERC's orders, exceptions could be established pursuant to regional rules
based on the need/appropriateness in a particular region.Consistent with the above discussion, if
the SDT elects to pursue revisions that accommodate shedding non-consequential load in
transmission planning for single contingency conditions, it should abandon the stakeholder
process approach. The establishment of exceptions is better suited for regional rules or pursuant
to a process outside of the reliability standards - e.g. via the Rules of Procedure, because such a
process is not suited for a continent-wide reliability standard. Regardless of whether the issue is
addressed via an external process, or left to regional variances, this issue needs to be addressed in
a relatively timely manner because the uncertainty is affecting planning processes.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. The SDT has set up
criteria for consideration in the potential usage of footnote ‘b’ for planning purposes in Attachment 1, Section II, Bullets 1 through 8.
The criteria described are objective. The process described does not tell a entity how to go about its business but only describes
what must be done to allow for the usage of footnote ‘b’ in the planning process. The SDT believes that the referenced exception
process is what is being proposed. The proposed process sets up an open and transparent process for allowing such Load shed in
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specific conditions and with specific limitations. Any future revisions to footnote 12 will be accomplished through the approved
standards development process and any discussion on changing threshold values would be part of that process. No change made.
Midwest Independent
Transmission System Operator,
Inc.

We do not support using a stakeholder process to determine if Non-conseqeuntial Load Loss is
appropriate following a single contingency event as a means to satisfy the standard. Stakeholder
processes will nearly always result in disagreements. The parties that may be responsible for
payment of upgrade costs will not necessarily line up with the parties adversely impacted by the
alternative load loss. If the stakeholder process includes all stakeholders, there may be many
more stakeholders impacted by upgrade costs based on broader benefits and/or cost sharing than
stakeholders impacted by the alternative load loss. This will result in the majority decision of a
stakeholder body to most often be one that supports load shed (until it is their turn to be the load
that is shed). On the other hand, if the stakeholder process is limited to only the stakeholders
directly impacted by the proposed load shed, to the extent those stakeholders pay only a small
part of the upgrade costs, they will always select a potentially costly upgrade to avoid load shed.
The point is, we do not believe that it possible to have a fair and impartial stakeholder process to
correctly determine if and when load shed is acceptable to assist in satisfying a single contingency
standard. Since the general intents of the existing TPL-002-1 standard and proposed TPL-001-2
standard are not to rely on any shedding of non-consequenital load to meet a single contingency
event, in the event that footnote b of TPL 002-1 or footnote 12 of TPL 001-2 is not eliminated, we
believe that it should be narrowly focused only on those situations for which the original footnote
was developed: interruption of service to radial customers or some local Network customers,
connected to or supplied by the Faulted element or by the affected area, where the overall
reliability of the interconnected transmission system is not impacted. We propose that footnote b
and footnote 12 be modified as follows to ensure it is not misapplied:”An objective of the planning
process is to avoid Non-Consequential Load Loss following Contingency events. In limited
circumstances, Non-Consequential Load Loss may be needed within the planning horizon to
ensure that BES performance requirements are satisfied. However, Non-consequential Load Loss
cannot be used to avoid cascading outages or to maintain system stability. Non-consequential
Load Loss also cannot be used to avoid a thermal loading or voltage limit violation on an EHV
facility. When Non-Consequential Load Loss is utilized within the planning horizon to address BES
performance requirements, such interruption cannot exceed 75 MW and is limited to the

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following circumstances: o Non-consequential Load Loss is allowed for load served by a radial
transmission line to avoid voltage limit violations on the radial transmission line following a single
contingency event anywhere on the system.. o Non-consequential load shed is allowed for load
within a local area served by not more than two transmission lines and/or transformers to avoid a
thermal loading issue or voltage issue in the local area, including the transmission lines and/or
transformers supplying the area, for a loss of one of the transmission lines or transformers
supplying the area, so long as there are no thermal loading or voltage violations outside the local
area.”We believe the language above maintains acceptable reliability on the bulk electric system
by limiting load shed and violations that require load shed to radial areas or areas that would be
served radially following the single contingency. We therefore highly recommend that
Attachment I be eliminated entirely and that the footnotes either be eliminated or replaced with
the modified version above.

Response: FERC remanded the standard; not because it contained a stakeholder process, but because the process was not well
defined, did not include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES
reliability would be maintained. The balloted draft added detail and specificity to the already approved approach. No change made.
SCE&G

While the current revisions improve the processes described, we have concerns regarding the
revisions to TPL002-1 b. SCE&G has significant concern with the proposed revision to TPL Table 1,
Footnote B. The current Footnote B states “Planned or controlled interruption of electric supply
to radial customers or some local Network customers, connected to or supplied by the Faulted
element or by the affected area, may occur in certain areas without impacting the overall
reliability of the interconnected transmission systems”. The phrase “without impacting the overall
reliability of the interconnected transmission systems” is important to the TPL standards to ensure
that ERO standards do not dictate the level of service to specific customers. Service to specific
customers and load pockets is jurisdictional to State Commissions. ERO standards should not
compromise this jurisdiction. SCE&G believes that any proposed revisions to Footnote B must
maintain the concept that planned or controlled interruption of electric supply to customers,
whether they are radial or network, is allowed as long as it does not impact the overall reliability
of the interconnected transmission systems. The proposed revision eliminates this concept

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Response: The SDT believes that the suggested wording is redundant as the quoted statement is the basis for standards activities.
No change made.
END OF REPORT

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
3. Initial ballot and comment period October 5, 2012 – November 19, 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions
1. Successive ballot

Anticipated Date
December 2012

2. Recirculation ballot

January 2013

3. BOT approval

February 2013

Draft 8: December 2012

1

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 8: December 2012

2

Standard TPL-001-2a — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-2a

4.1. Functional Entity

5.

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-001-2, 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-001-2a:










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)

B. Requirements

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3

Standard TPL-001-2a — Transmission System Planning Performance 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 :
•
•
•
•
•
•

Draft 8: December 2012

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.
Controllable Loads and Demand Side Management.

4

Standard TPL-001-2a — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

Draft 8: December 2012

5

Standard TPL-001-2a — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

Draft 8: December 2012

6

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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
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.

Draft 8: December 2012

7

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 8: December 2012

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

8

Standard TPL-001-2a — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

Draft 8: December 2012

9

Standard TPL-001-2a — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft 8: December 2012

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft 8: December 2012

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft 8: December 2012

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-2a — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft 8: December 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-2a — 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.
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).
Draft 8: December 2012

14

Standard TPL-001-2a — 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
Draft 8: December 2012

Standard TPL-001-2a — 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 does 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
In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW.
Once assurance has been received that the applicable regulatory authorities or governing bodies
responsible for retail electric service issues does 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.

Draft 8: December 2012

Standard TPL-001-2a — 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.

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Standard TPL-001-2a — 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
Draft 8: December 2012

Standard TPL-001-2a — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 8: December 2012

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.

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 8: December 2012

20

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 8: December 2012

21

Standard TPL-001-2a — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 8: December 2012

Action

Change Tracking

22

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
2.3. Initial ballot and comment period October 5, 2012 – November 19, 2012.
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. InitialSuccessive ballot

October December
2012

2. Recirculation ballot

December
2012January 2013

3. BOT approval

Draft 78: OctoberDecember 2012

February 2013

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 78: OctoberDecember 2012

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-2a

4.1. Functional Entity

5.

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-001-2, 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-001-2a:










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)

B. Requirements

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Standard TPL-001-2a — Transmission System Planning Performance 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.
Controllable Loads and Demand Side Management.

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

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Standard TPL-001-2a — Transmission System Planning Performance Requirements

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
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.

Draft 78: OctoberDecember 2012

7

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 78: OctoberDecember 2012

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

8

Standard TPL-001-2a — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

Draft 78: OctoberDecember 2012

9

Standard TPL-001-2a — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft 78: October December 2012

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft 78: October December 2012

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-2a — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft 78: October December 2012

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-2a — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft 78: October December 2012

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-2a — 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 Contingency 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.
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).
Draft 78: October December 2012

14

Standard TPL-001-2a — 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
Draft 78: October December 2012

Standard TPL-001-2a — Transmission System Planning Performance Requirements

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

b. AssessmentAn 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 mitigatealleviate 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 assure ensure that the applicable regulatory authorityauthorities or
governing bodybodies responsible for retail electric service issues does 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
In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW.
Once assurance has been received that the applicable regulatory authorityauthorities or
governing bodybodies responsible for retail electric service issues does 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 Non-Consequential Load Loss.

Draft 78: October December 2012

Standard TPL-001-2a — 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.

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Standard TPL-001-2a — 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
Draft 78: October December 2012

Standard TPL-001-2a — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 78: July December 2012

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.

19

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 78: July December 2012

20

Standard TPL-001-2a — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 78: July December 2012

21

Standard TPL-001-2a — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 78: July December 2012

Action

Change Tracking

22

Implementation Plan for TPL-001-2a
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
TPL-001-2a — Transmission System Planning Performance Requirements
In revising the TPL standards, the SDT is assuming that planners will receive valid data from the MOD
standards link described in TPL-001-2a, Requirement R1. Furthermore, there is a tacit assumption that
future revisions of the MOD standards will include steps to validate MOD based data.
Revision to Sections of Approved Standards and Definitions
There are multiple new definitions in the proposed standard.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission System performance and
Corrective Action Plans to remedy identified deficiencies.

Compliance with Standards
Standard
TPL-001-2a — Transmission
System Planning Performance
Requirements

Functions That Must Comply With the Associated Requirements
Transmission Planner
Planning Coordinator
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this standard.
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.

1

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-001-2, 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-001-2a:
•
•

•
•
•
•
•
•

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)

TPL-001-1a, TPL-002-1c, TPL-003-1b, and TPL-004-1a are being retired as they are replaced in their
entirety by TPL-001-2a. TPL-005-0 and TPL-006-0.1 are being retired because their requirements are
adequately covered by the revised TPL-001-2a and NERC’s Rules of Procedure, Section 800. TPL-0011a, TPL-002-1c, TPL-003-1b, TPL-004-1a, TPL-005-0 and TPL-006-0.1 are being retired on midnight

of the day immediately prior to the Effective Date of TPL-001-2a in the particular jurisdictions
in which TPL-001-2a is becoming effective. However, during this 24-month period, all aspects of
TPL-001-1a through TPL-006-0.1 shall remain in effect for compliance monitoring. This 24 month period
is to allow entities to develop, perform and/or validate new and/or modified studies, methodologies,
assessments, procedures, etc. necessary to implement and meet the TPL-001-2a requirements. The
specified effective dates are expected to allow sufficient time for proper assessment of the available
options necessary to create a viable Corrective Action Plan that is compliant with the new Standard.
R1. This Requirement is related to maintaining System models and the data needed to do so. This
requirement shall become effective on the first day of the first calendar quarter, 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
this requirement goes into effect on the first day of the first calendar quarter, 12 months after
Board of Trustees adoption.
R7. This Requirement identifies an obligation to determine individual and joint responsibilities
for performing studies needed to do the Planning Assessment. This requirement shall become
effective on the first day of the first calendar quarter, 12 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, this requirement goes

2

into effect on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption.
TPL-001-2a ‘raises the bar’ in several areas where performance requirements have been changed in the new
Standard versus those in existing TPL-001-1a, TPL-002-1c, TPL-003-1b and TPL-004-1a because loss of
Non-Consequential Load or interruption of firm transfers is no longer allowed for certain events, whereas the
existing Standards were interpreted by many to allow such actions. As shown in Table 1 of TPL-001-2a, the
performance requirements associated with the following events represent “raising the bar”:
•
•
•
•
•
•
•
•

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)

This “raising the bar” is beyond the control of the Transmission Planner and Planning Coordinator and
may have significant budget, siting, permitting, and construction impacts on many Transmission Owners.
To provide stakeholders with sufficient time to implement changes, a timeframe coincident with the end
of the Near-Term Transmission Planning Horizon has been provided
Any entity which cannot eliminate the need to trip Non-Consequential Load or curtail Firm Transmission
Service for these performance elements by that date shall submit a mitigation plan to its Regional Entity
outlining the steps it will take to correct the problem. If the entities follow the established ERO procedure
for mitigation, it is the intent of the SDT that no penalties will be assessed.

3

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
3. Initial ballot and comment period October 5, 2012 – November 19, 2012
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Successive ballot

December 2012

2. Recirculation ballot

January 2013

3. BOT approval

February 2013

Draft 7: December 2012

Page 1 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1c

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of the
first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

Draft 7: December 2012

Page 2 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

Draft 7: December 2012

Page 3 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

1c

February 2013

Address remand of proposed footnote ‘b’
pursuant to FERC Order RM06-16-009

Revised

Draft 7: December 2012

Page 4 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n ce Fo llowin g Lo s s o f a Sin g le BES Ele m e n t
Table I. Transmission System Standards — Normal and Emergency Conditions
Contingencies

Category

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

Draft 7: December 2012

Page 5 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. For purposes of this footnote, the following are not counted as Firm Demand t: (1)
Demand directly served by the Elements removed from service as a result of the Contingency, and (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout
the planning horizon to ensure that BES performance requirements are met. However, when interruption of Firm
Demand is utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements,
such interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in
Attachment 1. In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

Draft 7: December 2012

Page 6 of 13

S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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3.
4.
5.
6.
7.
8.

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ 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 does not object to the use of Firm Demand
interruption under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW
In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW.
Once assurance has been received that the applicable regulatory authorities or governing bodies
responsible for retail electric service issues does not object to the use of Firm Demand
interruption under footnote ‘b’, 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 ‘b’
for Firm Demand interruption.

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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will
be removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
2.3.Initial ballot and comment period October 5, 2012 – November 19, 2012
Proposed Action Plan and Description of Current Draft:
The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. Table 1 appears in the first four of the
current TPL standards but footnote ‘b’ only applies to TPL-002. Therefore, only TPL-002 is
being posted for industry comment at this time. When the footnote has been approved, all four
of the applicable TPL standards will be filed with the Commission.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. InitialSuccessive ballot

October December 2012

2. Recirculation ballot

December 2012January 2013

3. BOT approval

February 2013

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A. Introduction
1.

Title:

System Performance Following Loss of a Single Bulk Electric System
Element (Category B)

2.

Number:

TPL-002-1c

3.

Purpose:

System simulations and associated assessments are needed periodically to ensure
that reliable systems are developed that meet specified performance requirements
with sufficient lead time, and continue to be modified or upgraded as necessary
to meet present and future system needs.

4.

Applicability:
4.1. Planning Authority
4.2. Transmission Planner

5.

Effective Date: The application of revised Footnote ‘b’ in Table 1 will take effect on the first day
of the first calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of the
first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made effective
pursuant to the laws applicable to such ERO governmental authorities. All other requirements
remain in effect per previous approvals. The existing Footnote ‘b’ remains in effect until the
revised Footnote ‘b’ becomes effective.

B. Requirements
R1.

The Planning Authority and Transmission Planner shall each demonstrate through a valid
assessment that its portion of the interconnected transmission system is planned such that the
Network can be operated to supply projected customer demands and projected Firm (nonrecallable reserved) Transmission Services, at all demand levels over the range of forecast
system demands, under the contingency conditions as defined in Category B of Table I. To be
valid, the Planning Authority and Transmission Planner assessments shall:
R1.1.

Be made annually.

R1.2.

Be conducted for near-term (years one through five) and longer-term (years six
through ten) planning horizons.

R1.3.

Be supported by a current or past study and/or system simulation testing that
addresses each of the following categories, showing system performance following
Category B of Table 1 (single contingencies). The specific elements selected (from
each of the following categories) for inclusion in these studies and simulations shall
be acceptable to the associated Regional Reliability Organization(s).
R1.3.1. Be performed and evaluated only for those Category B contingencies that
would produce the more severe System results or impacts. The rationale for
the contingencies selected for evaluation shall be available as supporting
information. An explanation of why the remaining simulations would
produce less severe system results shall be available as supporting
information.
R1.3.2. Cover critical system conditions and study years as deemed appropriate by
the responsible entity.
R1.3.3. Be conducted annually unless changes to system conditions do not warrant
such analyses.

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R1.3.4. Be conducted beyond the five-year horizon only as needed to address
identified marginal conditions that may have longer lead-time solutions.
R1.3.5. Have all projected firm transfers modeled.
R1.3.6. Be performed and evaluated for selected demand levels over the range of
forecast system Demands.
R1.3.7. Demonstrate that system performance meets Category B contingencies.
R1.3.8. Include existing and planned facilities.
R1.3.9. Include Reactive Power resources to ensure that adequate reactive resources
are available to meet system performance.
R1.3.10. Include the effects of existing and planned protection systems, including any
backup or redundant systems.
R1.3.11. Include the effects of existing and planned control devices.
R1.3.12. Include the planned (including maintenance) outage of any bulk electric
equipment (including protection systems or their components) at those
demand levels for which planned (including maintenance) outages are
performed.

R2.

R1.4.

Address any planned upgrades needed to meet the performance requirements of
Category B of Table I.

R1.5.

Consider all contingencies applicable to Category B.

When System simulations indicate an inability of the systems to respond as prescribed in
Reliability Standard TPL-002-1_R1, the Planning Authority and Transmission Planner shall
each:
R2.1.

Provide a written summary of its plans to achieve the required system performance as
described above throughout the planning horizon:
R2.1.1. Including a schedule for implementation.
R2.1.2. Including a discussion of expected required in-service dates of facilities.
R2.1.3. Consider lead times necessary to implement plans.

R2.2.

R3.

Review, in subsequent annual assessments, (where sufficient lead time exists), the
continuing need for identified system facilities. Detailed implementation plans are not
needed.

The Planning Authority and Transmission Planner shall each document the results of its
Reliability Assessments and corrective plans and shall annually provide the results to its
respective Regional Reliability Organization(s), as required by the Regional Reliability
Organization.

C. Measures
M1. The Planning Authority and Transmission Planner shall have a valid assessment and corrective
plans as specified in Reliability Standard TPL-002-1_R1 and TPL-002-1_R2.
M2. The Planning Authority and Transmission Planner shall have evidence it reported
documentation of results of its reliability assessments and corrective plans per Reliability
Standard TPL-002-1_R3.
D. Compliance

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1.

Compliance Monitoring Process
1.1. Compliance Monitoring Responsibility
Compliance Monitor: Regional Reliability Organizations.
Each Compliance Monitor shall report compliance and violations to NERC via the NERC
Compliance Reporting Process.
1.2. Compliance Monitoring Period and Reset Timeframe
Annually.
1.3. Data Retention
None specified.
1.4. Additional Compliance Information
None.

2.

Levels of Non-Compliance
2.1. Level 1:

Not applicable.

2.2. Level 2: A valid assessment and corrective plan for the longer-term planning horizon is
not available.
2.3. Level 3:

Not applicable.

2.4. Level 4:
available.

A valid assessment and corrective plan for the near-term planning horizon is not

E. Regional Differences
1.

None identified.

Version History
Version

Date

Action

Change Tracking

0

April 1, 2005

Effective Date

New

0a

October 23,
2008

Added Appendix 1 – Interpretation of TPL002-0 Requirements R1.3.2 and R1.3.12
and TPL-003-0 Requirements R1.3.2 and
R1.3.12 for Ameren and MISO

Revised

0b

November 5,
2009

Added Appendix 2 – Interpretation of
R1.3.10 approved by BOT on November 5,
2009

Addition

1b

April 2010

Revised footnote ‘b’ pursuant to FERC
Order RM06-16-009.

Revised

1c

February 2013

Address remand of proposed footnote ‘b’
pursuant to FERC Order RM06-16-009

Revised

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Table I. Transmission System Standards — Normal and Emergency Conditions
Category

Contingencies

Initiating Event(s) and Contingency
Element(s)

A
No Contingencies
B
Event resulting in
the loss of a single
element.

System Limits or Impacts
System Stable
and both
Loss of Demand
Thermal and
or
Voltage
Cascading
Outages
Curtailed Firm
Limits within
Transfers
Applicable
Rating a

All Facilities in Service

Yes

No

No

Single Line Ground (SLG) or 3-Phase (3Ø) Fault,
with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.

Yes
Yes
Yes
Yes

No b
No b
No b
No b

No
No
No
No

Yes

Nob

No

Yes

Planned/
Controlledc
Planned/
Controlledc

No

Planned/
Controlledc

No

e

Single Pole Block, Normal Clearing :
4. Single Pole (dc) Line
e

C
Event(s) resulting in
the loss of two or
more (multiple)
elements.

SLG Fault, with Normal Clearing :
1. Bus Section
2. Breaker (failure or internal Fault)

Yes

No

e

SLG or 3Ø Fault, with Normal Clearing , Manual
System Adjustments, followed by another SLG or
e
3Ø Fault, with Normal Clearing :
3. Category B (B1, B2, B3, or B4)
contingency, manual system adjustments,
followed by another Category B (B1, B2,
B3, or B4) contingency

Yes

e

Bipolar Block, with Normal Clearing :
4. Bipolar (dc) Line Fault (non 3Ø), with
e
Normal Clearing :
5. Any two circuits of a multiple circuit
towerlinef

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

Yes

Planned/
Controlledc

No

7. Transformer

Yes

Planned/
Controlledc

No

8. Transmission Circuit

Yes

Planned/
Controlledc

No

9. Bus Section

Yes

Planned/
Controlledc

No

e

SLG Fault, with Delayed Clearing (stuck breaker
or protection system failure):
6. Generator

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D

d

Extreme event resulting in
two or more (multiple)
elements removed or
Cascading out of service

e

3Ø Fault, with Delayed Clearing (stuck breaker or protection system
failure):
1. Generator

3. Transformer

2. Transmission Circuit

Evaluate for risks and
consequences.


4. Bus Section
e

3Ø Fault, with Normal Clearing :



5. Breaker (failure or internal Fault)
6. Loss of towerline with three or more circuits
7. All transmission lines on a common right-of way
8. Loss of a substation (one voltage level plus transformers)



May involve substantial loss of
customer Demand and
generation in a widespread
area or areas.
Portions or all of the
interconnected systems may
or may not achieve a new,
stable operating point.
Evaluation of these events may
require joint studies with
neighboring systems.

9. Loss of a switching station (one voltage level plus transformers)
10. Loss of all generating units at a station
11. Loss of a large Load or major Load center
12. Failure of a fully redundant Special Protection System (or
remedial action scheme) to operate when required
13. Operation, partial operation, or misoperation of a fully redundant
Special Protection System (or Remedial Action Scheme) in
response to an event or abnormal system condition for which it
was not intended to operate
14. Impact of severe power swings or oscillations from Disturbances
in another Regional Reliability Organization.

a) Applicable rating refers to the applicable Normal and Emergency facility thermal Rating or system voltage limit as
determined and consistently applied by the system or facility owner. Applicable Ratings may include Emergency Ratings
applicable for short durations as required to permit operating steps necessary to maintain system control. All Ratings
must be established consistent with applicable NERC Reliability Standards addressing Facility Ratings.
b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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
the shedding of any Firm Demand. It is recognized that Firm For purposes of this footnote, the following are not
counted as Firm Demand will be interrupted if itt is: (1) Demand directly served by the Elements removed from service
as a result of the Contingency, orand (2) Interruptible Demand or Demand-Side Management Load. In limited
circumstances, Firm Demand may be interrupted throughout the planning horizon to ensure that BES performance
requirements are met. However, when interruption of Firm Demand is utilized within the Near-Term Transmission
Planning Horizon to address BES performance requirements, such interruption is limited to circumstances where the use
of Firm Demand interruption meets the conditions shown in Attachment 1. In no case can the planned Firm Demand
interruption under footnote ‘b’ exceed 75 MW.
c) Depending on system design and expected system impacts, the controlled interruption of electric supply to customers
(load shedding), the planned removal from service of certain generators, and/or the curtailment of contracted Firm (nonrecallable reserved) electric power Transfers may be necessary to maintain the overall reliability of the interconnected
transmission systems.
d) A number of extreme contingencies that are listed under Category D and judged to be critical by the transmission
planning entity(ies) will be selected for evaluation. It is not expected that all possible facility outages under each listed
contingency of Category D will be evaluated.
e) Normal clearing is when the protection system operates as designed and the Fault is cleared in the time normally expected
with proper functioning of the installed protection systems. Delayed clearing of a Fault is due to failure of any protection
system component such as a relay, circuit breaker, or current transformer, and not because of an intentional design delay.
f) System assessments may exclude these events where multiple circuit towers are used over short distances (e.g., station
entrance, river crossings) in accordance with Regional exemption criteria.

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Attachment 1
I. Stakeholder Process
During each Planning Assessment before the use of Firm Demand interruption under footnote ‘b’
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 ‘b’ 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 Firm Demand interruption under footnote ‘b’
c. Provisions for a stakeholder comment period
3. Information regarding the intended purpose and scope of the proposed Firm Demand
interruption under footnote ‘b’ (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
‘b’ 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 Firm Demand interruption under
footnote ‘b’ which must include the following:
1. Conditions under which Firm Demand interruption under footnote ‘b’ 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 Firm Demand MW to be interrupted with:
a. The estimated number and type of customers affected
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3.
4.
5.
6.
7.
8.

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

III. Instances for which Regulatory Review of Interruptions of Firm Demand under Footnote ‘b’
is Required
Before a Firm Demand interruption under footnote ‘b’ is allowed as an element of a Corrective
Action Plan in Year One of the Planning Assessment, the Transmission Planner or Planning
Coordinator must assureensure that the applicable regulatory authority authorities or governing
bodybodies responsible for retail electric service issues does not object to the use of Firm
Demand interruption under footnote ‘b’ 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 Firm Demand interruptions under footnote ‘b’, 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 Firm Demand interruption under footnote ‘b’ is greater than or equal to 25
MW
In no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW.
Once assurance has been received that the applicable regulatory authority authorities or
governing bodybodies responsible for retail electric service issues does not object to the use of
Firm Demand interruption under footnote ‘b’, 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 ‘b’ for Firm Demand interruption.
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Appendix 1
Interpretation of TPL-002-0 Requirements R1.3.2 and R1.3.12 and
TPL-003-0 Requirements R1.3.2 and R1.3.12 for Ameren and MISO
NERC received two requests for interpretation of identical requirements (Requirements R1.3.2 and
R1.3.12) in TPL-002-0 and TPL-003-0 from the Midwest ISO and Ameren. These requirements state:
TPL-002-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category B of Table 1
(single contingencies). The specific elements selected (from each of the following categories)
for inclusion in these studies and simulations shall be acceptable to the associated Regional
Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

TPL-003-0:
[To be valid, the Planning Authority and Transmission Planner assessments shall:]
R1.3

Be supported by a current or past study and/or system simulation testing that addresses each
of the following categories, showing system performance following Category C of Table 1
(multiple contingencies). The specific elements selected (from each of the following
categories) for inclusion in these studies and simulations shall be acceptable to the associated
Regional Reliability Organization(s).
R1.3.2

Cover critical system conditions and study years as deemed appropriate by the
responsible entity.

R1.3.12

Include the planned (including maintenance) outage of any bulk electric equipment
(including protection systems or their components) at those demand levels for which
planned (including maintenance) outages are performed.

Requirement R1.3.2
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from Ameren on July 25, 2007:
Ameren specifically requests clarification on the phrase, ‘critical system conditions’ in R1.3.2. Ameren
asks if compliance with R1.3.2 requires multiple contingent generating unit Outages as part of possible
generation dispatch scenarios describing critical system conditions for which the system shall be planned
and modeled in accordance with the contingency definitions included in Table 1.

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Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2
Received from MISO on August 9, 2007:
MISO asks if the TPL standards require that any specific dispatch be applied, other than one that is
representative of supply of firm demand and transmission service commitments, in the modeling of system
contingencies specified in Table 1 in the TPL standards.
MISO then asks if a variety of possible dispatch patterns should be included in planning analyses
including a probabilistically based dispatch that is representative of generation deficiency scenarios,
would it be an appropriate application of the TPL standard to apply the transmission contingency
conditions in Category B of Table 1 to these possible dispatch pattern.
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.2 was developed by
the NERC Planning Committee on March 13, 2008:
The selection of a credible generation dispatch for the modeling of critical system conditions is within the
discretion of the Planning Authority. The Planning Authority was renamed “Planning Coordinator” (PC)
in the Functional Model dated February 13, 2007. (TPL -002 and -003 use the former “Planning
Authority” name, and the Functional Model terminology was a change in name only and did not affect
responsibilities.)
−

Under the Functional Model, the Planning Coordinator “Provides and informs Resource Planners,
Transmission Planners, and adjacent Planning Coordinators of the methodologies and tools for the
simulation of the transmission system” while the Transmission Planner “Receives from the Planning
Coordinator methodologies and tools for the analysis and development of transmission expansion
plans.” A PC’s selection of “critical system conditions” and its associated generation dispatch falls
within the purview of “methodology.”

Furthermore, consistent with this interpretation, a Planning Coordinator would formulate critical system
conditions that may involve a range of critical generator unit outages as part of the possible generator
dispatch scenarios.
Both TPL-002-0 and TPL-003-0 have a similar measure M1:
M1.

The Planning Authority and Transmission Planner shall have a valid assessment and
corrective plans as specified in Reliability Standard TPL-002-0_R1 [or TPL-003-0_R1]
and TPL-002-0_R2 [or TPL-003-0_R2].”

The Regional Reliability Organization (RRO) is named as the Compliance Monitor in both standards.
Pursuant to Federal Energy Regulatory Commission (FERC) Order 693, FERC eliminated the RRO as the
appropriate Compliance Monitor for standards and replaced it with the Regional Entity (RE). See
paragraph 157 of Order 693. Although the referenced TPL standards still include the reference to the
RRO, to be consistent with Order 693, the RRO is replaced by the RE as the Compliance Monitor for this
interpretation. As the Compliance Monitor, the RE determines what a “valid assessment” means when
evaluating studies based upon specific sub-requirements in R1.3 selected by the Planning Coordinator and
the Transmission Planner. If a PC has Transmission Planners in more than one region, the REs must
coordinate among themselves on compliance matters.

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Requirement R1.3.12
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from Ameren on July 25, 2007:
Ameren also asks how the inclusion of planned outages should be interpreted with respect to the
contingency definitions specified in Table 1 for Categories B and C. Specifically, Ameren asks if R1.3.12
requires that the system be planned to be operated during those conditions associated with planned
outages consistent with the performance requirements described in Table 1 plus any unidentified outage.
Request for Interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12
Received from MISO on August 9, 2007:
MISO asks if the term “planned outages” means only already known/scheduled planned outages that may
continue into the planning horizon, or does it include potential planned outages not yet scheduled that
may occur at those demand levels for which planned (including maintenance) outages are performed?
If the requirement does include not yet scheduled but potential planned outages that could occur in the
planning horizon, is the following a proper interpretation of this provision?
The system is adequately planned and in accordance with the standard if, in order for a system operator
to potentially schedule such a planned outage on the future planned system, planning studies show that a
system adjustment (load shed, re-dispatch of generating units in the interconnection, or system
reconfiguration) would be required concurrent with taking such a planned outage in order to prepare for
a Category B contingency (single element forced out of service)? In other words, should the system in
effect be planned to be operated as for a Category C3 n-2 event, even though the first event is a planned
base condition?
If the requirement is intended to mean only known and scheduled planned outages that will occur or may
continue into the planning horizon, is this interpretation consistent with the original interpretation by
NERC of the standard as provided by NERC in response to industry questions in the Phase I development
of this standard1?
The following interpretation of TPL-002-0 and TPL-003-0 Requirement R1.3.12 was developed by
the NERC Planning Committee on March 13, 2008:
This provision was not previously interpreted by NERC since its approval by FERC and other regulatory
authorities. TPL-002-0 and TPL-003-0 explicitly provide that the inclusion of planned (including
maintenance) outages of any bulk electric equipment at demand levels for which the planned outages are
required. For studies that include planned outages, compliance with the contingency assessment for TPL002-0 and TPL-003-0 as outlined in Table 1 would include any necessary system adjustments which
might be required to accommodate planned outages since a planned outage is not a “contingency” as
defined in the NERC Glossary of Terms Used in Standards.

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S ta n d a rd TP L-002-1c — S ys te m P e rfo rm a n c e Fo llo win g Lo s s o f a S in g le BES Ele m e n t

Appendix 2
Requirement Number and Text of Requirement
R1.3. Be supported by a current or past study and/or system simulation testing that addresses each of the
following categories, showing system performance following Category B of Table 1 (single
contingencies). The specific elements selected (from each of the following categories) for inclusion in
these studies and simulations shall be acceptable to the associated Regional Reliability Organization(s).
R1.3.10. Include the effects of existing and planned protection systems, including any backup or
redundant systems.
Background Information for Interpretation
Requirement R1.3 and sub-requirement R1.3.10 of standard TPL-002-0a contain three key obligations:
1. That the assessment is supported by “study and/or system simulation testing that addresses each
the following categories, showing system performance following Category B of Table 1 (single
contingencies).”
2. “…these studies and simulations shall be acceptable to the associated Regional Reliability
Organization(s).”
3. “Include the effects of existing and planned protection systems, including any backup or
redundant systems.”
Category B of Table 1 (single Contingencies) specifies:
Single Line Ground (SLG) or 3-Phase (3Ø) Fault, with Normal Clearing:
1. Generator
2. Transmission Circuit
3. Transformer
Loss of an Element without a Fault.
Single Pole Block, Normal Clearinge:
4. Single Pole (dc) Line
Note e specifies:
e) Normal Clearing is when the protection system operates as designed and the Fault is cleared in the time
normally expected with proper functioning of the installed protection systems. Delayed clearing of a Fault
is due to failure of any protection system component such as a relay, circuit breaker, or current
transformer, and not because of an intentional design delay.
The NERC Glossary of Terms defines Normal Clearing as “A protection system operates as designed and
the fault is cleared in the time normally expected with proper functioning of the installed protection
systems.”
Conclusion
TPL-002-0a requires that System studies or simulations be made to assess the impact of single
Contingency operation with Normal Clearing. TPL-002-0a R1.3.10 does require that all elements
expected to be removed from service through normal operations of the Protection Systems be removed in
simulations.
This standard does not require an assessment of the Transmission System performance due to a Protection
System failure or Protection System misoperation. Protection System failure or Protection System
misoperation is addressed in TPL-003-0 — System Performance following Loss of Two or More Bulk

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Electric System Elements (Category C) and TPL-004-0 — System Performance Following Extreme
Events Resulting in the Loss of Two or More Bulk Electric System Elements (Category D).
TPL-002-0a R1.3.10 does not require simulating anything other than Normal Clearing when assessing the
impact of a Single Line Ground (SLG) or 3-Phase (3Ø) Fault on the performance of the Transmission
System.
In regards to PacifiCorp’s comments on the material impact associated with this interpretation, the
interpretation team has the following comment:
Requirement R2.1 requires “a written summary of plans to achieve the required system performance,”
including a schedule for implementation and an expected in-service date that considers lead times
necessary to implement the plan. Failure to provide such summary may lead to noncompliance that could
result in penalties and sanctions.

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Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-1: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-1c: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-1: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-1: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

 

Project 2010-11 Revision of TPL-002 footnote ‘b’
and TPL-001 Footnote 12
Unofficial Comment Form
 
Please DO NOT use this form for submitting comments.  Please use the electronic form located at the 
link below to submit comments on the Standard.  The electronic comment form must be completed by 
8:00 p.m. ET, January 11, 2013.  
 
If you have questions, please contact Ed Dobrowolski at [email protected] or by telephone at 
609‐947‐3673. 
 
Project page 
 
Background Information
This posting is soliciting formal comment. 
 
FERC Order No. 762 issued April 19, 2012 remanded TPL‐002‐1b as vague, unenforceable, and not 
responsive to the previous Commission directives on this matter.  The Standards Committee directed 
the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of Orders 
No. 693 and 762.  The SDT was also charged with revising the corresponding footnote 12 of TPL‐001‐2 
in order to prevent the remand of TPL‐001‐2.  
 
The NERC Board of Trustees approved version of TPL‐002‐1b was used as a starting point for these 
deliberations.  This was done because when FERC remanded the standard it was not because it 
contained a stakeholder process, but because the stakeholder process was not well defined, did not 
include quantitative and qualitative criteria for allowing curtailment of Firm Demand, and did not 
assure that BES reliability would be maintained. Thus, the initial balloted draft was designed to respond 
to those criticisms by adding the necessary detail and specificity to the already approved approach. 
 
TPL‐001‐2 has been approved by the industry through the standards development process and by the 
NERC Board of Trustees.  The Standards Authorization Request (SAR) for this project recognized this 
fact and thus did not allow for any changes to the utilization of footnote 12.  Nothing in this project 
changes the application of footnote 12 within Table 1 of TPL‐001‐2. 
 
 

 

 
 
Project YYYY‐##.# ‐ Project Name

 
The remand order from FERC requested that a Section 1600 data request be made to provide data on 
the actual usage of footnote ‘b’ by planners.  The SDT utilized the data received in reaching its 
determination of the threshold values applied in the footnote and believes that the data request 
results provide a sufficient technical rationale for the threshold values.  Furthermore, the SDT believes 
that any deviation from the thresholds derived from the actual data may be viewed as unacceptable in 
addressing the directives in Orders . 
 
The proposed stakeholder process does not eliminate or reduce the role of local regulatory authorities, 
nor does it impose on local regulatory proceedings.  The proposed stakeholder process was designed 
to incorporate an open and transparent proceeding to the potential utilization of footnote ‘b’ with all 
affected parties involved in the discussions.  Local regulatory authorities are still free to perform their 
legislative mandates.   
 
The SDT has made a number of clarifying changes to the footnote and Attachment based on comments 
received from the initial ballot posting.  These changes include clarifying that Consequential Load Loss 
and Demand‐Side Management programs are not affected by application of the footnote. The 
questions in this comment form are restricted to these changes.  There have been no changes to the 
Implementation Plan originally filed with the respective standards. 
 
The SDT requests that commenters refrain from repeating comments submitted in the previous 
posting.  The SDT has noted those comments and responded to them to the best of its ability within 
the project constraints. 
 
You do not have to answer all questions.  Enter All Comments in Simple Text Format.  Bullets, 
numbers, and special formatting will not be retained.    
Insert a “check” mark in the appropriate boxes by double‐clicking the gray areas. 
 
1. Do you agree with changes made to the body of the footnote?  If you do not support these changes 
or you agree in general but feel that alternative language would be more appropriate, please provide 
specific suggestions in your comments.     
 Yes  
 No  
Comments:
 

 

Unofficial Comment Form | Project 2010‐11 Revisions to TPL Footnote ‘b’ 

2 

 
 
Project YYYY‐##.# ‐ Project Name

2. Do you agree with the changes contained in Section II of Attachment 1?  If you do not support these 
changes or you agree in general but feel that alternative language would be more appropriate, please 
provide specific suggestions in your comments. 
 Yes  
 No  
Comments:            
 
3. Do you agree with changes contained in Section III of Attachment 1?  If you do not support these 
changes or you agree in general but feel that alternative language would be more appropriate, please 
provide specific suggestions in your comments. 
 
 Yes  
 No  
Comments:            
 
4. If you have any other comments on this Standard that you haven’t already mentioned above, and 
that are not simply reiterating previous comments that the SDT has already responded to, please 
provide them here: 
 
Comments:            
 

Unofficial Comment Form | Project 2010‐11 Revisions to TPL Footnote ‘b’ 

3 

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Successive Ballot is now open through Friday, January 11, 2013
Now Available
A successive ballot is now open for revisions to a single footnote that is incorporated into two
standards (TPL-002-1c– System Performance Following Loss of a Single BES Element for footnote ‘b’,
and TPL-001-2a – Transmission System Planning Performance Requirements for footnote 12 ) through
8 p.m. Eastern Friday, January 11, 2013.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions

Members of the ballot pools associated with this project may log in and submit their vote for the
footnote by clicking here.
Next Steps
The ballot results will be announced and posted on the project page. The drafting team will consider
all comments received during the formal comment period and successive ballot and, if needed, make
revisions to the footnote. If the comments do not show the need for significant revisions, the footnote
will proceed to recirculation ballot.
As a reminder, the drafting team will hold a webinar to review the revisions on Tuesday, January 8,
2013, from 1:00 to 3:00 p.m. Eastern. Please click here to register for this webinar.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of

Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Formal Comment Period: December 10, 2012 – January 11, 2013
Upcoming:
Successive Ballot: January 2, 2013 – January 11, 2013
Now Available
A 30-day formal comment period and successive ballot is open for revisions to a single footnote that is
incorporated into two standards (TPL-002-1c– System Performance Following Loss of a Single BES
Element for footnote ‘b’, and TPL-001-2a – Transmission System Planning Performance Requirements
for footnote 12 ) through 8 p.m. Eastern Friday, January 11, 2013.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions for Commenting

A formal comment period on the single footnote that is incorporated into TPL-002-1c and TPL-001-2a is
open through 8 p.m. Eastern on Friday, January 11, 2013. Please use this electronic form to submit
comments. If you experience any difficulties in using the electronic form, please contact Monica
Benson at [email protected]. An off-line, unofficial copy of the comment form is posted on the
project page.
Next Steps
The drafting team will hold a webinar to review the revisions on Tuesday, January 8 from 1:00 to 3:00
p.m. Eastern. Registration instructions for this webinar will be provided in a separate announcement.
The drafting team will consider all comments received during the formal comment period and
successive ballot and, if needed, make revisions to the footnote. If the comments do not show the
need for significant revisions, the footnote will proceed to recirculation ballot.

Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Formal Comment Period: December 10, 2012 – January 11, 2013
Upcoming:
Successive Ballot: January 2, 2013 – January 11, 2013
Now Available
A 30-day formal comment period and successive ballot is open for revisions to a single footnote that is
incorporated into two standards (TPL-002-1c– System Performance Following Loss of a Single BES
Element for footnote ‘b’, and TPL-001-2a – Transmission System Planning Performance Requirements
for footnote 12 ) through 8 p.m. Eastern Friday, January 11, 2013.
Please note that, aside from the proposed revisions to the footnote and changes to conform the
Enforcement Dates section to the current language approved by NERC legal to cover all of the
jurisdictions in which NERC standards are mandatory, no other revisions have been made to either
standard. The scope of the drafting team’s assignment is limited to addressing changes to the single
footnote.
Instructions for Commenting

A formal comment period on the single footnote that is incorporated into TPL-002-1c and TPL-001-2a is
open through 8 p.m. Eastern on Friday, January 11, 2013. Please use this electronic form to submit
comments. If you experience any difficulties in using the electronic form, please contact Monica
Benson at [email protected]. An off-line, unofficial copy of the comment form is posted on the
project page.
Next Steps
The drafting team will hold a webinar to review the revisions on Tuesday, January 8 from 1:00 to 3:00
p.m. Eastern. Registration instructions for this webinar will be provided in a separate announcement.
The drafting team will consider all comments received during the formal comment period and
successive ballot and, if needed, make revisions to the footnote. If the comments do not show the
need for significant revisions, the footnote will proceed to recirculation ballot.

Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-1c, footnote ‘b’ and TPL-001-2a, footnote 12
Successive Ballot Results
Now Available
A successive ballot window for revisions to a single footnote that is incorporated into two standards
(TPL-002-1c– System Performance Following Loss of a Single BES Element for footnote ‘b’, and TPL001-2a – Transmission System Planning Performance Requirements for footnote 12) concluded at 8
p.m. Eastern on Friday, January 11, 2013.
Voting statistics for each ballot are listed below, and the Ballot Results page provides a link to the
detailed results.
Approval
Quorum: 85.47%
Approval: 65.77%
Next Steps
The drafting team will consider all comments received during the formal comment period and, if
needed, make revisions to the footnote. If the comments do not show the need for significant
revisions, the footnote will proceed to a recirculation ballot.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.

Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process. The success of the NERC standards development process depends on stakeholder
participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

NERC Standards

 

Newsroom  •  Site Map  •  Contact NERC

  
Advanced Search

 
User Name

Ballot Results

Ballot Name: Project 2010 -11 Successive Ballot

Password

Ballot Period: 1/2/2013 - 1/11/2013
Ballot Type: Successive

Log in

Total # Votes: 306

Register
 

Total Ballot Pool: 358
Quorum: 85.47 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
65.77 %
Vote:
Ballot Results: The drafting team will review comments received.

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
102
10
82
25
73
48
0
8
3
7
358

#
Votes

 
1
0.9
1
1
1
1
0
0.5
0.2
0.6
7.2

#
Votes

Fraction
 

54
4
38
8
30
21
0
2
0
5
162

Negative

No
# Votes Vote

Fraction

 
0.771
0.4
0.679
0.8
0.75
0.636
0
0.2
0
0.5
4.736

Abstain

 

 

16
5
18
2
10
12
0
3
2
1
69

0.229
0.5
0.321
0.2
0.25
0.364
0
0.3
0.2
0.1
2.464

 
19
0
15
8
21
10
0
0
1
1
75

13
1
11
7
12
5
0
3
0
0
52

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
 
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.

Member

Ballot

 
Vijay Sankar
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Scott J Kinney

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Comments
 

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain

 

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
Corporate Risk Solutions, Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
FortisBC
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.

Kevin Smith
Christopher J Scanlon
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Tony Kroskey
John Brockhan
Joseph Turano Jr.
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Joseph Doetzl
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Curtis Klashinsky
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative

Affirmative
Affirmative

Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine

Negative
Negative
Affirmative

Michael Moltane

Affirmative

Ted Hobson
Walter Kenyon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Mark Ramsey
Michael Jones
Cole C Brodine

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Randy MacDonald
Bruce Metruck
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Green Cove Springs
City of Homestead
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina

Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Affirmative

Dale Dunckel

Abstain

Rod Noteboom

Abstain

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Rodney A. Wilson
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Gregg R Griffin
Orestes J Garcia
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee
Peter T Yost
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Affirmative
Negative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
Abstain
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Negative
Negative
Negative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4

Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
American Municipal Power
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.

Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
David McDowell
Gary Clear
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kevin Koloini
Ronnie Frizzell
Duane S Dahlquist
Reza Ebrahimian

Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative

Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative

Affirmative

Tim Beyrle
Nicholas Zettel
John Allen

Abstain
Abstain

Margaret Powell

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Integrys Energy Group, Inc.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Energy Services, Inc.
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern Indiana Public Service Co.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission

David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Christopher Plante
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative

John D Martinsen

Abstain

Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Edward F. Groce
Clement Ma

Abstain
Abstain
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative

Affirmative

Mike D Kukla
Francis J. Halpin
Shari Heino
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Christy Wicke
Marcus Ellis
Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper
Kenneth Dresner
David Schumann
Preston L Walsh
John J Babik
Brett Holland
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Kim Morphis
Mahmood Z. Safi
Richard K Kinas

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Affirmative
Affirmative

Affirmative
Abstain
Affirmative

Abstain
Negative
Abstain
Affirmative
Abstain
Abstain
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative

NERC Standards
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6

Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Mississippi Electric Power Association
Southern California Edison Company

Roland Thiel
Matt E. Jastram
Annette M Bannon
Tim Kucey
Steven Grega
Michiko Sell
Lynda Kupfer
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Nickesha P Carrol
David J Carlson
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
David Ried
Kelly Cumiskey
Carol Ballantine
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Joel Rogers
Lujuanna Medina

https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Abstain
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Negative
Abstain
Negative

NERC Standards
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Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
JDRJC Associates
Massachusetts Attorney General
Transmission Strategies, LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

John J. Ciza

Negative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Affirmative
Negative
Affirmative

Peter H Kinney

Affirmative

David F Lemmons
Edward C Stein
Roger C Zaklukiewicz
Jim Cyrulewski
Frederick R Plett
Bernie M Pasternack
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann

Negative

Negative
Negative
Affirmative
Affirmative
Negative

Donald Nelson

Abstain

Diane J. Barney

Negative

Thomas G. Dvorsky
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Donald G Jones
Steven L. Rueckert
 

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https://standards.nerc.net/BallotResults.aspx?BallotGUID=bae24049-4d6d-4175-9df4-68c41d94cb32[1/15/2013 11:41:19 AM]

Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
 

 

 

Name (32 Responses)
Organization (32 Responses)
Group Name (17 Responses)
Lead Contact (17 Responses)
Contact Organization (17 Responses)
IF YOU WISH TO EXPRESS SUPPORT FOR ANOTHER ENTITY'S COMMENTS WITHOUT ENTERING ANY ADDITIONAL
COMMENTS, YOU MAY DO SO HERE. (4 Responses)
Comments (49 Responses)
Question 1 (38 Responses)
Question 1 Comments (45 Responses)
Question 2 (32 Responses)
Question 2 Comments (45 Responses)
Question 3 (30 Responses)
Question 3 Comments (45 Responses)
Question 4 (29 Responses)
Question 4 Comments (45 Responses)

Individual
Frederick R Plett
Massachusetts Attorney General
No
The SDT ignored a lot of feedback concerning the inappropriateness of a 75 MW threshold. IT remains inappropriate and an
appropriate level should be decided by local stakeholder processes.
Yes
No
Don't buy the 75 MW or the 25 MW thresholds.
Group
SERC EC Planning Standards Subcommittee
Jim Kelley
PowerSouth Energy Cooperative
Yes
Yes
Yes
Change "does" to "do" in the last sentence of the first paragraph and in the first sentence of the last paragraph in Section III of
Attachment 1.
We continue to recommend that up to 25 MW of planned interruption be allowed without triggering the need for a stakeholder
process. We believe that this simplification would be less burdensome and would enhance industry acceptance of the revision,
while still meeting regulatory guidance. The comments expressed herein represent a consensus of the views of the above-named
members of the SERC EC Planning Standards Subcommittee only and should not be construed as the position of SERC Reliability
Corporation, its board, or its officers.
Individual
Thad Ness
American Electric Power
Yes
Yes
Yes
No
Individual
Oliver Burke
Entergy Services, Inc. (Transmission)
No

Attachment 1 is overly burdensome and concerns local reliability issues better left to local regulators. A planned or unplanned loss
of 25 MW is inconsequential to the reliability of the BES. The footnote could be simplified to exclude attachment 1 as follows: An
objective of the planning process is to minimize the likelihood and magnitude of Non-Consequential Load Loss following
Contingency 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 25 MW and notice must be given to applicable regulatory authorities or governing bodies responsible for retail electric
service issues within 30 days of the completion of the assessment which includes the use of footnote 12.
No
Attachment 1 is overly burdensome and unnecessary.
No
Attachment 1 is overly burdensome and unnecessary.
Yes
If Attachment 1 must remain, Entergy would support the SERC PSS suggestion to limit the application of Attachment 1 (the
stakeholder process) to only those situations where the non-consequential load at risk is above 25MW.
Individual
Chris de Graffenried
Consolidated Edison Co. of NY, Inc.
No
Planned interruptions of Firm Demand in response to a Single Contingency (as directed in Footnote b of TPL-002 Table 1, and
Footnote 12 of TPL-001-2), is not an acceptable corrective action to mitigate reliability issues on the BES system. The
Interconnected System should be designed and operated with enough transfer capacity to be able to withstand, at a minimum, a
single contingency event without service interruptions to customer load. Systems must be designed and operated so that the
impact of any single contingency can be mitigated by re-dispatching available system resources without the need to implement
load shedding.

Group
Northeast Power Coordinating Council
Guy Zito
Northeast Power Coordinating Council
No
Dropping load generally should not be endorsed, but it is recognized that there are special situations where it cannot be avoided. If
a regulator responsible for load is comfortable with greater than 75MW being dropped in a rare situation, there should not be a
requirement to build out of the situation. Provided there is no widespread, adverse effect on the reliability of the interconnected
BES, the effect of a interruption on customers is under the purview of the applicable regulatory authority that is responsible for
local transmission and retail service over the load to be curtailed. NERC must acknowledge that jurisdictional authorities can decide
on the parameters for planning events that do not have an impact on the reliability of interconnected BES . There are no limits on
non-consequential load loss for Single Contingency P2-2 and P2-3 (HV only), multiple Contingencies P4 and P5 (HV only), and P6
and P7. Footnote 12 allows limited non-consequential load loss for single contingency P1, Multiple Contingency P3. Nonconsequential load loss is not allowed for P2-2 and P2-3 (EHV), and P4 and P5 (EHV). Considering the extensive EHV Facilities in
the Canadian regions of NPCC, it is not reasonable to accept some non-consequential load loss for single contingency P1 and P2-3,
and then deny it for Multiple Contingency categories P4 and P5 which are statistically less frequent than the former. Also, the
Multiple Contingency P7 (for which there is no limit on non-consequential load loss) is more frequent than P2-3, P4 and P5. This
technical irregularity must be reviewed and addressed. This comment was submitted for the last posting.
Yes
Yes

Individual
David Jendras
Ameren
Yes
Yes
Yes
We find no substantive changes to section III, and still believe that no objection from a regulatory body requires, at a minimum, a
tacit approval.

Group
Southwest Power Pool Reliability Standards Development Group
Jonathan Hayes
Southwest Power Pool
Yes
Yes
Yes
Yes
Under section II items 3 and 4 the wording (frequency and duration) seems to implicate that the planners will be determining
these events in a probabilistic manor. If the probability of these events is anything other than 0 planners will have to accommodate
for those events in their planning assessments regardless of how small the probability is for that event.
Individual
Nazra Gladu
Manitoba Hydro
Yes
Manitoba Hydro agrees that the changes add clarity to the footnote.
No
Any assessment or explanation is only speculation. Is the requirement any different? Item 5 raises an expectation that footnote 12
can only be used on an interim bases – this should be clarified.
Yes
Manitoba Hydro cannot support the Footnote B attachment which imposes a stakeholder process not required in Manitoba.
Individual
David Wang
SDG&E
No
Table 1, footnote b of TPL-002 allows the use of load shedding for the loss of a single element (Category B) under certain
circumstances. SDG&E has been against the proposed changes because of the addition of a stakeholder process that allows outside
entities to make reliability decisions which we would be held accountable for.
No
No
No
Individual
Bob Easton
WAPA-RMR
No
While Western agrees in general with what is proposed in Footnote b; I do not agree with stipluating 2 requirements in the
proposed Footnote b: The 75 MW load threshold; the Attachment 1 Stakeholder process. The 75 MW seems low and NERC should
condsider using a 300 MW threshold similar to that used in CIP-002 and EOP-004 requirements.
Yes
No
See response to Question 1.
Yes
I believe that the 75 MW limit is abetrary and could be too low given particular circumstances, like the maginitude of recent load
growth in the area, regulatory hurdles in building new transmission, etc. I also believe that the Attachment 1 stakeholder process
is not needed, since it is already covered by the FERC Ordered 890 planning process.
Group
Bonneville Power Administration
Jamison Dye
Transmission Reliability Program

Yes
Yes
Yes
No
Group
TVA Transmission Reliability Engineering and Controls
Tim Ponseti, VP
Bulk Transmission Engineering
Yes
Yes
Yes
We recommend that up to 25 MW of planned interruption be allowed without triggering the need for a stakeholder process. We
believe that this simplification would be less burdensome and would enhance industry acceptance of the revision, while still
meeting regulatory guidance.
Group
Santee Cooper
Terry L. Blackwell
Santee Cooper
No
Santee Cooper will abstain from voting on the revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL001-2. Santee Cooper is concerned that the revised language oversteps the bounds of the "reliability standard" definition under
Section 215 of the Federal power Act and into customer service issues that are better served by, and under the jurisdiction of,
state and local utility boards and commissions. However, in the spirit of moving this process forward, Santee Cooper will not vote
against the revised footnotes.

Individual
Kenn Backholm
Public Utility District No.1 of Snohomish County

Yes
The Public Utility District No.1 of Snohomish County will abstain from voting on the revisions to footnote "b" in TPL-002-1c and the
corresponding footnote 12 of TPL-001-2. The Public Utility District No.1 of Snohomish County is concerned that the revised
language oversteps the bounds of the "reliability standard" definition under Section 215 of the Federal power Act and into customer
service issues that are better served by, and under the jurisdiction of, state and local utility boards and commissions (for details on
the Public Utility District No.1 of Snohomish County's concerns please see the comments submitted during the initial ballot).
However, in the spirit of moving this process forward, the Public Utility District No.1 of Snohomish County will not vote against the
revised footnotes.
Group
seattle city light
paul haase
seattle city light

Yes
SCL abstains from voting on the revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL-001-2. SCL is

concerned that the revised language oversteps the bounds of the "reliability standard" definition under Section 215 of the Federal
power Act and into customer service issues that are better served by, and under the jurisdiction of, state and local utility boards
and commissions (for details onSCL's concerns please see the comments submitted during the initial ballot). However, in the spirit
of moving this process forward, SCL will not vote against the revised footnotes.
Individual
Steve Alexxanderson P.E.
Central Lincoln

Yes
Central Lincoln has not paid much attention to this standard, since it is not applicable to this entity's registered functions. However,
we are disturbed by the direction the standard is taking. The slides from the recent webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf) state that "The 75 MW cap will require
construction of major Transmission projects." This is in direct conflict with the definition of "reliability standard" as provided in
section 215 of the FPA where it states "...the term does not include any requirement to enlarge such facilities or to construct new
transmission capacity..." The webinar slide does offer alternatives to construction, but we don't see those providing any reliability
benefit. Some of the suggestions apparently only relate to contract language, which cannot possibly relate in any way to "reliable
operation" as defined in section 215. Central Lincoln is is concerned that the revised language oversteps the bounds of the
"reliability standard" definition under Section 215 of the Federal power Act and into customer service issues that are better served
by, and under the jurisdiction of, state and local utility boards and commissions.
Individual
Milorad Papic
Idaho Power Company
Yes
Yes
Yes
No
Individual
Russ Schneider
Flathead Electric Cooperative, Inc.
Agree
We support the comments submitted by Central Lincoln
Individual
Cheryl Moseley
Electric Reliability Council of Texas, Inc.
No
See response to question 4.
No
See response to question 4.
No
See response to question 4.
Yes
ERCOT believes that the revisions to the footnote b attachment are an improvement from the previous version. However, ERCOT
does not believe that the SDT provided a technical rationale for disagreeing with the comments that we previously submitted. We
fundamentally disagree with the approach of defining a stakeholder process in the attachment to a footnote in a reliability
standard. While footnotes and attachments have been used in other standards we believe that this application is not appropriate.
ERCOT believes that the footnote should be removed altogether as it does not meet the objectives of FERC Order 693. We also
believe that FERC did not mandate that a stakeholder process be used. As stated in the January 8 NERC Industry Webinar, 90% of
planning entities have not used the existing footnote b over a planning horizon of 13 years. To incorporate an attachment to a
footnote with a complicated and prescriptive stakeholder process to address a few instances seems to be a least common
denominator approach to planning which is opposed to FERC’s direction. Consistent with the approach of TPL-001-2, ERCOT
recommends raising the bar on reliability and removing the footnote from the standard.
Individual
Jim Cyrulewski
JDRJC Associates LLC
Agree

Midwest ISO
Individual
Kathleen Goodman
ISO New England Inc
No
There are jurisdictional issues with the footnote and attachment as written. These will be described in further detail throughout this
document. The footnote itself states, “An objective of the planning process is to minimize the likelihood and magnitude of NonConsequential Load Loss following planning events.” A standard should not have requirements described as objectives, this
language is extremely subjective.
No
Section II, 2.a, states that studies must address the estimated number and type of customers affected by Non-Consequential Load
Shedding. The Transmission Planner in many cases will not be the appropriate entity to address these concerns. The Transmission
Owner, Distribution Provider or Load Serving Entities would be the appropriate entities to address customer affects. Explaining
effects on the “health, safety, and welfare of the community” is required under the footnote in Section II, 2.b. The same load could
be shed directly as the consequence of a fault and no such assessment is required. In addition, Transmission Planners can shed
radial load with no assessment of health and welfare. In addition to the practical considerations listed, once again here the
standard infringes on Section 215 responsibilities where State authority over the “safety, adequacy and reliability of the electric
system in that state” is mandated. This section should be deleted. Section II, requirements 3 and 4 discuss estimating frequency
and duration of Non-Consequential Load Loss based on historical performance. The planning process uses deterministic not
probabilistic assessments. This section should be deleted.
The footnote states “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 does not object to the use of NonConsequential Load Loss under footnote 12 if either...”. Section 215 of the Federal Power Act clearly delineates Federal, State and
Local authority. State and Local requirements should not be introduced into a NERC standard. In addition to the jurisdictional
issues, proving that the “applicable regulatory authority or governing body” does not object is more difficult than proving that they
simply approved the use of non-consequential load loss. The SDT should remove all references to State and Local authority from
the standard. Overall, the order of Section III is also notable. During year, two through ten of the overall planning horizon the
standard allows for Non-Consequential Load Loss without approval. In the first year of the assessment, approval becomes required
for Non-Consequential Load Loss. At this point, it is too late to allow for any other alternative. The Regional Entities with NERC
oversight perform periodic audits and require self-certification of the planning process. By virtue of the audit and self-certification
process, NERC has the ability to monitor the use of Non-Consequential Load Loss in planning assessments. State and Local
approval of practices called for in ERO Standards is inappropriate. In addition to being notable for the year one timing, Section III
seems incomplete. In the case where there is objection to Non-Consequential Load Shedding, the process appears to end without
resolution.
In summary, this standard as proposed has misplaced jurisdictional authority under Section 215 of the Federal Power Act. The
removal of references to State and Local authorities in the standard is required.
Individual
John Collins
Platte River Power Authority
No
Disagree with no change to the 75 MW threshold, but agree with the minor changes that were made since last posting. I request
your consideration of a 300 MW threshold similar to that used in CIP-002 and EOP-004. Since there is a directive for some
threshold, and in an attempt to reduce the likelihood of over-burdening smaller communities, the 300 MW level would be a more
reasonable threshold for the BES.
Yes
No
See answer to Question 1.
No
Individual
Keith Morisette
Tacoma Power
Yes
Yes
Yes
While Tacoma Power appreciates NERC's attempt to address both footnotes with the same drafting team, Tacoma Power is voting
negative on the revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL-001-2. However, Tacoma Power
would vote affirmative if a re-circulation ballot was limited strictly to footnote "b" in TPL-002-1c. TPL-001-2 considered new types

of outages not considered by TPL version 1, such as P2-1. Although TPL-001-2 was approved by the industry, the proposed
modifications to footnote 12 in TPL-001-2 are significantly more onerous than footnote 12 in TPL-001-2. Furthermore, since TPL001-2 is not yet enforceable, some Transmission Planners still do not realize that automatic relay actions are considered Non
Consequential Load Loss. In addition, Tacoma Power identified over 100 MW of load in multiple locations that would be shed in
accordance with footnote 12 in TPL-001-2. Unfortunately, the structure of the Section 1600 data request did not allow for the
submittal of footnote 12 related data. Since it is clear that the potential impact of the footnote 12 revision has not been addressed
due to the compressed timeline, Tacoma Power believes that by separating the two standards, NERC can meet the FERC mandated
deadline for footnote b while still continuing the drafting process to achieve true industry consensus on footnote 12. Please note
that FERC orders 693 and 762 require addressing only footnote "b" by the using the Expedited Standards Development Process.
Earlier FERC orders discuss "single contingencies" as type Category B in TPL-002-1; FERC has not addressed Non Consequential
Load Shedding for the lower probability "single contingencies" (i.e. P2-1) in TPL-001-2. Approving the revisions to footnote 12
would result in negligible reliability gains at an unreasonable cost for customers on the fringes of the power system, without
affording local jurisdictional cost benefit analysis. Tacoma Power is also concerned that the revised language oversteps the bounds
of the "reliability standard" definition under Section 215 of the Federal Power Act. These revisions tread on customer service issues
that are better served by, and under the jurisdiction of, state and local utility boards and commissions. For details on Tacoma
Power's concerns please see the comments submitted during the initial ballot. However, in the spirit of moving this process
forward, Tacoma Power would vote to approve the revisions to solely TPL-002-1c if balloted separately from TPL-001-2. Tacoma
Power appreciates the opportunity to provide comments, and thanks you for consideration of our comments.
Individual
Donald Weaver
New Brunswick System Operator

We do not agree with setting a MW limit for non-consequential load loss. The allowable amount should be determined and
approved by the jurisdiction of the area(s) whose load is affected. The intent of the TPL standard and this footnote is to ensure that
if non-sequential load loss is accounted for or relied up to ensure BES reliability (as assessed in the planning horizon), that such a
decision needs to be approved by the appropriate jurisdiction
Group
ACES Standards Collaborators
Ben Engelby
ACES
Yes
(1) We continue to disagree with the 75 MW capacity limit threshold. There is no need for a 75 MW cap because registered entities
and local-level policy makers are in the best position to determine an appropriate capacity limit, as stated in the FERC order and in
previous feedback. However, if the drafting team decides to move forward with a cap, we suggest using a cap that would reflect all
data points from the Section 1600 data request to be under the threshold. The findings to the data request contained a data point
at 75.2 MW, which would be over the proposed threshold. We understand this data point, in essence, has been omitted because
the use of non-consequential load shedding for the 75.2 MW data point is expected to terminate soon. If the drafting team intends
to use the data that represents the actual usage of footnote ‘b’ by planning coordinators, then the team should take into account
the highest data point and adjust the threshold to at least 76 MW regardless of the length of time the data point is needed. Again,
local decision makers are better equipped to make this type of determination. (2) However, in the spirit of moving forward with
this project we will support the changes and thank the drafting team for their efforts.
No
(1) Thank you for making the changes to Section II of Attachment 1. We believe the modification of removing “assessments” and
replacing it with “explanation” provides more flexibility regarding how a registered entity can demonstrate the impacts the health,
safety and welfare of the community. (2) However, we still believe that the word “alleviate” in bullet 5 requires the same actions as
the word “mitigate.” There are instances where no action is required based on a variety of factors. We recommend the following:
“Future plans, if necessary, to mitigate/alleviate the need for Non-Consequential Load Loss under footnote 12, unless a
determination was made not to mitigate/alleviate, then an explanation why.”
Yes
Yes
(1) In regard to the changes relating to Demand-Side Management, we agree with the wording, “For purposes of this footnote, the
following are not counted as Firm Demand: (1) Demand directly served by the Elements removed from service as a result of a
Contingency, or (2) Interruptible Demand or Demand-Side Management Load.” However, the most recent change has created
some confusion by replacing “or” with “and” that potentially and inadvertently may exclude the use of DSM in all locations but on
the facilities removed from service. This would render DSM ineffective. Now, the both (1) and (2) must occur in order to not be
counted as Firm Demand. We recommend changing the wording back to “or” so each option (1) OR (2) is independently excluded
from Firm Demand for footnote b. Connecting the options with the word “and” changes the meaning and requires entities to meet
both option (1) and option (2) to be excluded from Firm Demand. Demand directly served by the Elements removed from service
as a result of a Contingency should be excluded, as should Interruptible Demand or Demand-Side Management Load regardless of
its location. A registered entity does not need to have both for the exclusion. (2) Thank you for the opportunity to comment.
Group
NARUC
Diane Barney

NARUC
No
As stated before, if there is no reliability threat to the bulk system there is no need for the 75 MW limit on the anticipated amount
of load to be shed. As long as the regulator responsible for the retail load subject to being shed is notified of the situation, the
situation can be appropriately addressed at the local level.

Group
MRO NSRF
WILL SMITH
MIDWEST RELIABILITY ORGANIZATION
Yes
No
The drafting team over specified the Section II stakeholder information process and continues to disregard comments that item 2b
be removed from several utilities over several footnote “b” revisions. The goal of Attachment 1 as stated by the drafting team chair
was to place “meaningful” parameters around footnote b. The words in 2b on “health, safety, and welfare” are beyond the scope of
NERC standards, and are not defined sufficiently in the standard to make the requirement meaningful. The NSRF recommends that
if the drafting team doesn’t eliminate 2b, they delete the words “on the health, safety, and welfare of the community” as going
beyond NERC jurisdiction, FERC directives, and the SAR. The drafting team response that similar words exist in another standard is
not a reason to the ambiguous words in the TPL Attachment 1.
No
The NSRF believes that the standards drafting team did clarify in the webinar that the 25 MW and 75 MW footnote “b” values were
separate from interruptible load, and consequential load loss and would not be counted towards the 25 and 75 MW thresholds.
However, the NSRF recommends that Attachment 1 also clearly contain an explicit statement “the 25 MW and 75 MW footnote “b”
values are separate from consequential load loss, interruptible load, and are not to be counted towards the 25 MW and 75 MW
thresholds.”
Yes
Some entities remain concerned over a potential conflict and mismatch of impacts introduced by Section III and the inclusion of
non-regulated stakeholders versus NERC regulated entities. There was not a FERC directive to include section III. Section III
overreaches the intent of the FERC order and the SAR to meet the FERC directive. The drafting team should show the specific FERC
requirement and words in Order 693 that requires non-NERC regulatory reviews. The drafting team technically responded to a
request that Section III be removed, but avoided the the fundamental issue. The fact that some existing non-NERC regulatory
bodies may already have a consistent practice is not a reason to include non-NERC entities into a NERC framework. This creates a
fundamental mismatch between NERC regulated entities that must follow NERC standards and stakeholders that are not compelled
by NERC requirements. If Section III is not deleted, it is recommended that wording be added to allow the existing FERC Order 890
stakeholder meeting process be used to meet Attachment 1. Regulators attend these meetings and all stakeholders (including
regulators) could be asked for their objections. If there was no response or a “lack of dissent”, this would be documented as
meeting Attachment 1 to allow the use of footnote “b” without additional special procedures.
Group
Duke Energy
Greg Rowland
Duke Energy
Yes
Yes
Yes
No
Group
Hydro One Networks Inc.
Sasa Maljukan
Hydro One Networks Inc.
No
In this comment period Hydro One would like to reiterate its initial comments. Hydro One disagrees with prescribing a fixed MW
threshold for Non-Consequential Load Loss in a continent-wide standard. Provided there is no widespread, adverse effect on the
reliability of the interconnected bulk electric system, the effect on customers of a firm demand interruption is the responsibility of

the applicable regulatory authority or its delegated agencies responsible for local transmission and retail service over the load to be
curtailed. If it is decided to proceed with the 75 MW or any other value, we propose replacing the sentence, in the footnote and in
attachment one, section III that reads: “In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75
MW.” with “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 under footnote 12 for a non-US Registered Entity should be determined by
the applicable Regulatory Authority or Governmental Authority or its delegated agency in that is responsible for retail electric
service issues in that jurisdiction.”
No
As previously stated, we believe that the process presented in Section II is overly prescriptive. If a section that prescribes the
information requirements for a stakeholder process is required, then for non-US entities this section should simply require that the
process information requirements must be in accordance with the requirements of the applicable Regulatory Authority or
Governmental Authority or its delegated agency that is responsible for local transmission and retail service in that jurisdiction.
No
The process presented in Section III is overly prescriptive and duplicates information not necessary for its intended purpose. As
stated in Q1, we disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard, and
propose alternate language in our response to Q1. If this section is required to address a review of the use of footnote 12 to ensure
that there are no wide-spread adverse reliability impacts on the bulk power system, then it should be limited to the information
required for that purpose. Provided there is local support for the use of Non-Consequential Load Loss under footnote 12, only
information items 6 and 8 from section II are relevant for this assessment—the remainder are not required for this section and
should be deleted. Items 1 and 2 complicate this section and are unnecessary. They should be replaced by a phrase such as “for
those planning events where the use of footnote 12 is referenced.” We disagree with the need to submit this information to the
ERO for a determination of whether there are any Adverse Reliability impacts caused by the use of Non-Consequential Load Loss.
This will introduce a new type of review at the ERO that will create unnecessary delays and burden, and is inconsistent with (and
not required for) all of the other performance requirements in the TPL standards. Submitting the analysis to the adjacent Planning
Coordinators and Transmission Planners, and any functional entity that requests it, as called for in requirement R8 of TPL-001-2
should be sufficient.
Yes
As previously stated in our response to Question #1, Hydro One would like to reiterate our position presented during the initial
comment period. We believe that the SDTs response to our initial comments did not correctly address the issues because it did not
recognize the Reliability Standards framework that is effective in the Province of Ontario and possibly other Canadian provinces.
Individual
Michiko Sell
Public Utility District No. 2 of Grant County, WA
No
GCPD abstains from voting on the revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL-001-2. GCPD is
concerned that the revised language oversteps the bounds of the "reliability standard" definition under Section 215 of the Federal
Power Act and into customer service issues that are better served by, and under the jurisdiction of, state and local utility boards
and commissions. However, in the spirit of moving this process forward, GCPD did not vote against the revised footnotes.

Individual
Michael Moltane
ITC
MISO
Yes
Yes
Yes
Yes
While ITC is voting yes for this “successive ballot”, we are doing so in the interest of ensuring that TPL 001-2 becomes fully
effective as soon as possible. TPL001-2 is a major improvement to previous standards and insuring it becomes fully effective is
important to ITC and the industry. However, we have concerns that we would like to be noted. Because footnote B has been
highlighted and expanded, there is the possibility of future “unintended consequences”. It is highly likely that interveners or others
may attempt to stop or slow down needed corrective action plans, that do not rely on load shedding, by suggesting that planners
use this stakeholder process before proposing projects. We suggest both NERC and FERC be prepared to deal with these
unintended consequences. We also concur in entirety with the comments MISO is proposing to make for this project. They are
consistent with past comments ITC has made and do discuss in some detail the potential “unintended consequences” this detailed
footnote may cause.
Group
Western Area Power Administration - Transmission Owner
Lloyd A. Linke
Western Area Power Administration

No
While Western generally agrees with the proposed modification to footnote b, Western does not support the 75 MW threshold and
Attachment 1 Stakeholer process. The 75 MW threshold seems to low and if a threshold it needed the drafting team should
consider using a 300 MW threshold similar to that used in CIP-002, EOP-004, DOE OE-417 reporting, and NERC event analysis
process. The stakeholder process seems to be duplicative, considering there FERC Order 890 planning process.
Yes
No
See answer to Question 1.
Yes
Western believes that the 75 MW limit is arbitrary and could be to low given particular circumstances, like the magnitude of recent
load growth in the area, regulatory hurdles in building new transmission, etc. We also believe that the Attachment 1 stakeholder
process is not needed, since it is already covered by the FERC Order 890 process.
Individual
Mark Westendorf
MISO
No
MISO does not object to the changes made to the body of the footnote since the previous draft. However, as a general matter,
MISO cannot support the current language of Footnote 12. Because the intent of the TPL standards is not to rely on nonconsequential firm load shedding after a single contingency event, MISO does not agree that footnote b in NERC TPL-002-1 and/or
footnote 12 in TPL-001-2 should be included in these standards. Nonetheless, if these footnotes are included, MISO agrees that
there should be some limitation on how much firm load shed is allowed under these footnotes and would not object to the
proposed 75 MW level if the footnotes are included.
No
Regarding the use of “explanation” in place of “assessment,” MISO understands that the purpose of this change is to reduce the
need for entities to hire expensive consultants and to incur other substantial costs in assessing demographic data and impacts on
an affected area. However, as written, this word change potentially places more of a burden on responsible entities. An assessment
is an analysis performed using available facts and data while an explanation implies full knowledge. MISO therefore recommends
that “assessment” be retained and that a footnote explaining the meaning of that term be added. More generally, however, MISO
has concerns regarding the use of a stakeholder process such as the one outlined in Attachment 1 and cannot support the Footnote
or Attachment 1 at this time. Please refer to our comments under Question 4 for a more detailed description of these concerns.
No
MISO does not object to the changes made to Section III. However, more generally, MISO has concerns regarding the use of a
stakeholder process such as the one outlined in Attachment 1 and cannot support the Footnote or Attachment 1 at this time.
Please refer to our comments under Question 4 for a more detailed description of these concerns.
Yes
As previously stated, it is the general intent of the existing TPL-002-1 standard and proposed TPL-001-2 standard to not rely on
any shedding of Non-Consequenital Load to meet a single contingency event. Accordingly, MISO submits that footnote b of TPL002-1 and footnote 12 of TPL-001-2 should be struck. However, in the event that the footnotes in question are not eliminated, the
footnote should be narrowly focused only on those situations for which the original footnote was developed, i.e., the interruption of
service to radial customers or some local area Network customers connected to or supplied by the Faulted element or by the
affected area, where the overall reliability of the interconnected transmission system is not impacted. MISO therefore proposes the
following alternate language for footnote b and footnote 12 to ensure it is not misapplied: “An objective of the planning process is
to avoid Non-Consequential Load Loss following Contingency events. In limited circumstances, Non-Consequential Load Loss may
be needed within the planning horizon to ensure that BES performance requirements are satisfied. However, Non-consequential
Load shed cannot be used to avoid cascading outages or to maintain system stability. Non-consequential load shed also cannot be
used to avoid a thermal loading or voltage limit violation on an extra high voltage (EHV) facility. When Non-Consequential Load
Loss is utilized within the transmission planning horizon to address BES performance requirements, such interruption cannot
exceed 75 MW and is limited to the following circumstances: • Non-consequential Load shed is allowed for load served by a radial
transmission line to avoid voltage limit violations on the radial transmission line following a single contingency event. • Nonconsequential load shed is allowed for load within a local area served by not more than two Transmission Circuits and/or
Transformers to avoid a thermal loading issue or voltage issue within the local area, including the Transmission Circuits and/or
Transformers directly supplying the local area, for a loss of a single element within the local area, including one of the
Transmission Circuits or Transformers directly supplying the local area, so long as there are no thermal loading or voltage
violations outside the local area.” MISO believes the language above would ensure the continuing reliability of the Bulk Electric
System by limiting load shed and violations that require load shed to radial areas or areas that would be served radially following
the single contingency. In addition, MISO has significant concerns regarding use of a stakeholder process to determine if nonconseqeuntial load shedding is appropriate following a single contingency event, as expressed in MISO’s comments on previous
drafts of this Project. In particular, MISO has concerns regarding whether such a stakeholder process could be sufficiently open and
transparent given the many, competing interests of the responsible entity and affected stakeholders. Without such sufficient
openness and transparency, it is likely that stakeholder processes will not result in consistent determinations of the
appropriateness of the application of footnote b in NERC TPL-002-1 and/or footnote 12 in TPL-001-2. Stated differently, MISO is
concerned that such stakeholder processes will always be subject to the biases of the participating parties, with the sheer number
of parties determining the outcome of the process. As an example, should a particular process be dominated by parties that may
be responsible for payment of upgrades but that are not impacted by the alternative load shed, those stakeholders impacted by the
alternative load loss would be relegated to a minority position, resulting in majority-imposed stakeholder decisions to shed load.
On the other hand, if the stakeholder process is limited to only the stakeholders directly impacted by the proposed load shed, to

the extent those stakeholders pay only a small part of the upgrade costs, they will always choose to avoid load shed – even if such
decision requires a potentially costly upgrade. Consequently, MISO has concerns that the inclusion of a requirement for a fair and
impartial stakeholder process to determine if and when load shed is acceptable to assist in satisfying a single contingency standard
is not realistically attainable. MISO therefore recommends that Attachment I be eliminated and that the footnotes either be
eliminated or replaced with the modified version above.
Individual
Michael R. Lombardi
Northeast Utilities
No
Northeast Utilities does not support the use of non-consequential demand interruption throughout the planning horizon. Even with
the 75 MW limit, NU believes that this language seems to encourage operational workarounds and adds burdens for operators of
the system. Lastly, NU believes this use of non-consequential load loss during the planning horizon is not consistent with planning
a highly reliable bulk electric system and thus does not support non-consequential load loss for planning purposes.

Individual
Patricia Robertson
BC Hydro

Yes
BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c – System Performance Following Loss of a Single BES
Element (footnote b) and TPL-001-2a – Transmission System Planning Performance Requirements (footnote 12). BC Hydro votes
YES in support of this ballot and wishes to provide the following two comments: 1.At this time BC Hydro has concerns about the
level of stakeholder consultation that might be required as a result of the implementation of this standard and will bring this
concern to the attention of our regulator if necessary. 2.At this time BC Hydro has concerns about the instances for which
regulatory review of non-consequential load loss under footnote 12 is required and will discuss those with our regulator if
necessary.
Individual
Teresa Czyz
Georgia Transmission Corp.
Yes
Since this question refers to both footnote b (TPL-002-1c) and footnote 12 (TPL-001-2a), and the changes to the footnotes are not
identical, the question should be split into two. Regarding footnote b: An excerpt from footnote b reads “For purposes of this
footnote, the following are not counted as Firm Demand (1) Demand directly served by the Elements removed from service as a
result of the Contingency …” However, what is being described is in fact Firm Demand (That portion of the Demand that a power
supplier is obligated to provide except when system reliability is threatened or during emergency conditions) that is Consequential
Load Loss (All Load that is no longer served by the Transmission system as a result of Transmission Facilities being removed from
service by a Protection System operation designed to isolate the fault.). Therefore, why not use the terms Consequential Load Loss
and Non-Consequential Load Loss? Regarding footnote 12: The replacing the NERC defined “Contingency” event with the undefined
“planning” event necessitates a new definition. The intent of the change is unclear.
Yes
Yes

Group
Southern Company
Shih-Min Hsu
Southern Company Services, Inc
Yes
Yes
Yes
Yes
Footnote b contains no technical basis for allowing load dropping. It is completely based on an administrative procedure. This is not

responsive to paragraphs 17 and 32 of the FERC remand order. A technical basis has to be proposed. The "temporarily radial"
concept that was proposed in earlier drafts will address this problem. It will give a technical basis for when load dropping would be
allowed. If a technical basis is developed like FERC requires, then there is no need for a stakeholder process. The stakeholder
process is not a bright line criteria which can be enforced; it will change depending on the make-up of stakeholders and therefore
create inconsistencies across the grid. This approach should never be used in a reliability standard. NERC adopted the ANSI
standard process as the bench mark in developing its reliability standards. ANSI does not use stakeholder processes. We propose
that the stakeholder process be eliminated. Create a technical basis for when load dropping can be utilized. Keep the 75 MW
maximum amount of load that can be dropped.
Individual
Si Truc PHAN
Hydro-Quebec TransEnergie
No
Hydro-Québec TransÉnergie (HQT) remains unconvinced that a MW threshold needs to be part of footnote 12. This is not a BES
reliability issue but only a matter of service continuity to be addressed by TO/PA/RC with local regulatory authorities.

No
HQT still considers that the non application of footnote 12 to categories P2 (breaker fault), P4 (stuck breaker) and P5 (failure of a
non redundant relay) is not correct, when the footnote is applied to other categories such as P3, P6 and P7 (loss of double-circuit
lines). The SDT has indicated that the applicability of footnote 12 to categories P2, P4 and P5 is not included in Project 2012-11.
However, looking at related Project 2006-02 where footnote 12 was brought up to Table 1, the matter of applicability was not
discussed in detail and the SDT did not clearly explain why Non-Consequential Load Loss was not allowed for contingencies less
frequent than those for which it is allowed (internal breaker faults or stuck breakers are less probable than double-circuit line
faults). Discussion on this matter should not be dismissed.
Individual
Clay Young
SCE&G
No
Comments previously submitted.
No
Comments previously submitted.
No
Comments previously submitted.
No
Individual
Michael Falvo
Independent Electricity System Operator
No
Please note that the Independent Electricity System Operator (IESO), an RTO/ISO registered under Industry Segment 2, has filed
an appeal with respect to NERC’s response to our similar comments submitted to the previous ballot on this project. We disagree
with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard. Provided there is no
widespread adverse effect on the reliability of the interconnected bulk power system, the effect on customers of a firm demand
interruption is the responsibility of the applicable regulatory authority or its agencies responsible for local transmission and retail
service over the load to be curtailed. To recognize NERC’s role as the ERO for Ontario and the Memorandum of Understanding
between NERC and the Ontario Energy Board, the IESO proposed replacing the sentence, in the footnote and in attachment one,
section III that reads: “In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is a Canadian Entity (or a Mexican Entity)
should be implemented in a manner that is consistent with/or under the direction of the Applicable Governmental Authority or its
agency in Canada (or Mexico). Under this language, both the amount of non-consequential load loss, and the process under which
that amount was arrived at, including stakeholder consultations, would be determined by the relevant Canadian jurisdiction, in this
case Ontario. This change will make the standard acceptable in Ontario’s legislative framework, in which NERC standards come into
force automatically unless, by order of the Ontario Energy Board, a standard is stayed and remanded back to NERC for further
consideration. The responses to the IESO’s comments in the previous ballot were inaccurate as to this key feature of the Ontario
reliability framework, as addressed in the IESO appeal. An alternate solution to this issue, which would • be consistent with the
intent of the responses to the IESO comments on the previous ballot, • respect the Ontario reliability framework, and • resolve the
IESO January 9, 2013 appeal; and is appropriate given that these changes are being driven by a U.S. FERC remand order to NERC,
would be to make the following highlighted clarifications to footnotes ‘b’ and 12: With respect to Standard TPL-002-1c — footnote
‘b’ b) An objective of the planning process is to minimize the likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is allowed 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 the shedding of any Firm
Demand. It is recognized that Firm For purposes of this footnote, the following are not counted as Firm Demand will be interrupted

if itt is: (1) Demand directly served by the Elements removed from service as a result of the Contingency, orand (2) Interruptible
Demand or Demand-Side Management Load. In limited circumstances, Firm Demand may be interrupted throughout the planning
horizon to ensure that BES performance requirements are met. However, for U.S. registered entities when interruption of Firm
Demand is utilized within the Near-Term Transmission Planning Horizon to address BES performance requirements, such
interruption is limited to circumstances where the use of Firm Demand interruption meets the conditions shown in Attachment 1. In
no case can the planned Firm Demand interruption under footnote ‘b’ exceed 75 MW for U.S. registered entities. With respect to
Standard TPL-001-2a — footnote 12: 12. An objective of the planning process is to minimize the likelihood and magnitude of NonConsequential Load Loss following Contingency 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, for U.S. registered
entities 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 U.S. registered entities.
No
No. The process presented in Section II is overly prescriptive. If a section that prescribes the information requirements for a
stakeholder process is required, then for Canadian entities this section should simply state that any threshold should be established
in a manner consistent with other service levels that apply to local transmission and retail service for the load to be curtailed, for
the reasons described in Q1.
No
The process presented in Section III is overly prescriptive and requires information not necessary to the intended purpose. As
stated in Q1, we disagree with prescribing a fixed MW threshold for Non-Consequential Load Loss in a continent-wide standard, and
propose alternate language as stated in Q1 comments and supporting reasons. If this section must deal with a review of the use of
footnote ‘b’/’12’ to ensure that there are no widespread adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local support for the use of Non-Consequential Load Loss
under footnote ‘b’/’12’, only information items 6 and 8 from section II are relevant for this assessment—the remainder are not
required for this section and should be deleted. The use of footnote ‘b’/’12’ should not be limited to the Near-Term Planning
Horizon. We propose that the words “in Year One of the Planning Assesssment” be deleted. Items 1 and 2 complicate this section
and are unnecessary. They should be replaced by a phrase such as “for those planning events where the use of footnote ‘b’/’12’ is
referenced”. We disagree with the need to submit to the ERO for a determination of whether there are any adverse reliability
impacts caused by the use of Non-Consequential Load Loss. This will introduce a new type of review at the ERO that will create
unnecessary delays and burden, and is inconsistent with and not required for all of the other performance requirements in the TPL
standards. Submitting the analysis to the adjacent Planning Coordinators and Transmission Planners, and any functional entity that
requests it, as called for in requirement R8 of TPL001-2 should be sufficient.
(1) The IESO reiterate its support for allowing load interruption for a single contingency with sufficient review/oversight and under
acceptable conditions, including no widespread adverse impact on the reliability of the interconnected bulk power system. The
reliability aspects (BES performance requirements) should be reviewed for acceptability by the adjacent Planning Coordinators and
Transmission Planners. However, issues pertaining to economics or externalities which may not be directly reliability-related are
always available for review and debate by the stakeholders via the regulatory processes and subject to approval by the regulatory
authority of each jurisdiction (including those in Canada and Mexico). (2) Furthermore, we request that Table 1 of TPL-001-3
(previous TPL-001-2 approved by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5 categories to allow the
application of footnote ‘b’/’12’ that is allowed for the P1 events. Events in P2, P4, and P5 can involve more elements and can be
more onerous and stressful to the system than the P1 events, and if use of footnote ‘b’/’12’ is permitted in the less stressful P1
events, it should also be permitted in P2, P4 and P5 events. There continues to be confusion as to this inconsistency, and to how
this is to be applied (as discussed at the last webinar). (3) We suggest that NERC Standards and their requirements should focus
on what is the anticipated outcome rather than how to achieve it. Accordingly, we believe that the focus of footnote ‘b’, and
footnote 12 should be that interruption of load must not have a widespread, adverse impact on the reliability of the interconnected
bulk power system. A continent-wide standard should not concern itself with the reliability of supply or supply continuity for local
load, as that is the responsibility of the applicable regulatory authority or its agencies responsible for local transmission and retail
service over the load to be curtailed. As mentioned above, NERC Standards and their requirements should focus on what is the
anticipated outcome rather than how to achieve it. In this regard, we believe that Attachment 1 is not necessary because it
prescribes a process which goes beyond the outcome of the standard and dictates how stakeholdering must be carried out. The
individual jurisdiction should establish the process for ensuring compliance with the standard and decide to what extent a
stakeholdering process is necessary to establish the acceptable level of load rejection for the area in a manner consistent with local
transmission established service levels. (4) The process presented in Section I is overly prescriptive. If a section that prescribes the
principles of a stakeholder process is required, then for Canadian entities this section should simply state that any threshold should
be established in a manner consistent with other service levels that apply to local transmission and retail service for the load to be
curtailed, as described in Q1 and for the reasons stated therein. Corrective action plans can rarely be implemented in a one-year
time frame, and in some cases, limited use of Non-consequential Load Loss will be preferable to unaffordable transmission
enhancements, therefore we believe that the use of footnote ‘b’/’12’ should not be limited to the Near-Term Transmission Planning
Horizon. We propose that the phrase “the Near-Term Transmission Planning Horizon of” be deleted from the opening paragraph.
Individual
Brett Holland
Kansas City Power & Light
Agree
SPP
Group
Iberdrola USA
John Allen
Rochester Gas & Electric

No
See comment to question 4 below.
No
See comment to question 4 below.
No
See comment to question 4 below.
Yes
The reasons for the “negative” vote are enumerated in our prior comments. In summary: 1. Attachment 1 is cumbersome and
inappropriate, and should be stricken entirely. 2. All non-consequential load loss for all single-element contingencies should be
temporary, with an action plan to avoid such load loss in the future. 3. All actions following single-element contingencies should be
an attempt to restore lost customer service, not interrupt more customers.
Individual
Darryl Curtis
Oncor Electric Delivery Company LLC
Yes
Yes
Yes
No
Individual
Vijayraghavan bangalore
Pacific gas and Electric Comapny
No
We do not agree with the imposition of a maximum limit on the amount of planned Firm Demand interruption under footnote b.
This addition is overly prescriptive, unnecessary, and can have unintended consequences on service reliability. Assigning a fixed
“not to exceed” number of MW in a continent-wide standard is overly prescriptive. A single number cannot account for variation
even within one BA Area. A fixed maximum number of MW for Non-Consequential Load Loss under Footnote b in TPL-002 (and
footnote 12 in TPL-001-3) is not necessary. The first sentence of this footnote states, “[a]n objective of the planning process
should be to minimize the likelihood and magnitude of interruption of firm transfers or Firm Demand following Contingency
events”. It is clear that the spirit of the TPL Standard is to minimize the likelihood and magnitude of Firm Demand interruption.
Adding a fix maximum number of MW would seem unnecessary at best. At worst, it could have unintended consequences. Without
a fixed maximum Non-Consequential Load Loss, the Transmission Planner understands that the objective is to minimize the
magnitude of the planned interruption under footnote b (TPL-001-3, footnote 12). Adding a maximum number of MW of planned
Firm Demand loss could have the effect of giving “safe harbor” to allow planned loss of that amount of load under Footnote b. The
Transmission Planner may now have more difficulty in avoiding Non-Consequential Firm Demand Loss that is less than the “not to
exceed” amount.
No
Suggest removing item 5, “A dispute resolution process for any question or concern raised in #4 above that is not resolved to the
stakeholder’s satisfaction”. Given that the “applicable regulatory authorities or governing bodies responsible for retail electric
service issues” are only one of the many affected stakeholders, it is unclear how this dispute resolution process would treat
stakeholders with different concerns. For example, how would such a dispute resolution process take into account the cost-benefit
balance of load loss, which is the responsibility of the authorities responsible for retail rates, if such an authority is only one of the
many stakeholders subject to dispute resolution?
No
We disagree with the inclusion of the information in Section II.2.a (the estimated number and type of customers affected) and
II.2.b (An assessment of the use of Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of the
community). We suggest removing them. Section II.2.a is an administrative process and not needed for reliability of the Bulk
Power System. Section II.2.b is vague and can be interpreted numerous ways, which make compliance difficult. It can also become
a legal liability issue for the service provider, even if that loss of load is judged to be a prudent decision by the “applicable
regulatory authorities or governing bodies responsible for retail electric service issues”.
No
Group
Tri-State G&T
Chris Pink
Chris Pink
No
1. In the last submittal for comments, the following comment was made: It was not clear how transmission projects with long lead
times (such as T-lines) would be handled by “Footnote b.” In other words, it is not clear if it is acceptable for a TP to plan for

shedding Firm Demand in the Near Term Planning Horizon without meeting the conditions shown in “Attachment 1” when a
mitigating project is planned that cannot be constructed in the Near Term Planning Horizon. The The Standard Drafting Team
(SDT) provided the following response: Any instance of proposed load shed for a single Contingency situation in a Planning
Assessment must meet the conditions of footnote ‘b.’ No Change made. From the above comments, we believe there is a situation
where the Bulk Electric System (BES) reliability is compromised while stakeholder process proceeds.
No
2. As stated previously, NERC Functional Model definitions for Planning Authorities and Transmission Planners do not include the
types of activities being proposed in “Attachment 1.” As written, this standard mandates functions on functional entities that are
outside those defined by the NERC Functional Model. The SDT acknowledged this by stating that “the NERC Functional Model is a
guideline for activities required of cited functional entities.” As such, we still believe that obligations should not be required of
entities outside of the NERC Functional Model descriptions.
No
3. Previously, it was commented that it is unclear how section III of “Attachment 1” would be applied to entities that only deliver
wholesale electric service and not retail electric service. The response provided by the SDT stated the following: The SDT believes
that the wholesale customer will be one of the stakeholders included in the process and any use of footnote must go through the
stakeholder process. No change made. If the wholesale customer is one of the stakeholders, the standard needs to add wholesale
customers into the language as part of Attachment I. For example, it should read as follows: Coordinator must ensure that the
applicable regulatory authorities, wholesale customers, or governing bodies responsible for retail electric service issues does not
object to the use of Firm Demand interruptions under footnote ‘b’…
Group
National Grid
Michael Jones
National Grid

Yes
We are accepting the standard as written because our current practices are better then the prescribed maximum limit. However,
we believe the appropriate limit should be determined on a case by case basis with the state regulator input. This standard as
written, does give us the flexibility to do this.
Individual
Alice Ireland
Xcel Energy

Yes
While we are not satisfied with the responses to our previous comments, we have chosen to not reiterate them here. Instead, we
feel that the need to continue with any modification to Footnote b seems moot considering FERC's recent approval of the revised
BES definition. Specifically, we believe exclusions E1 and E3, regarding radial systems and local networks, resolves FERC's original
directive on ambiguity with footnote b. We recommend the team consider abandoning this project, and request that NERC staff
request relief from FERC on the related directives, as they have been overcome by the modified BES definition.
Individual
Tony Kroskey
Brazos Electric Power Cooperative, Inc.
Agree
ACES Power Marketing

Consideration of Comments
Project 2010-11 Revision of TPL-002 footnote ‘b’

The Project 2010-11 TPL Table 1 Order Drafting Team thanks all commenters who submitted comments
on the proposed standards, TPL-002. The standard was posted for a 30-day public comment period
from December 12, 2012 through January 11, 2013. Stakeholders were asked to provide feedback on
the standards and associated documents through a special electronic comment form. There were 49
sets of comments, including comments from approximately 132 different people from approximately
48 companies representing 9 of the 10 Industry Segments as shown in the table on the following pages.
Summary Consideration:
The SDT made one change to the proposed standards to address industry comments. This change was
made in the main body of the footnote to address a specific jurisdictional concern for non-US entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW for US registered entities. The amount
of planned Non-Consequential 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.
In order to avoid confusion, a duplicative statement on the applicability of the 75 MW constraint was
deleted from Section III.
The SDT also corrected the grammar in Section III, changing ‘does’ to ‘do’ in the applicable sentences,
as follows:
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail
electric service issues does not object …”
In addition, in the course of researching industry comments, a typo was discovered and corrected as
follows:
TPL-002-1c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as
Firm Demand t: (1) …”
No other changes were made.
While the revision for non-US registered entities qualifies as a significant change to the standards, the
Standards Committee has decided that since the indicated change was simply for a jurisdictional issue,
and did not change the technical content or intent of the standard, that this project can be moved
forward to the recirculation ballot stage.

Unresolved minority issues:
Some respondents continue to raise jurisdictional concerns with the proposed standards. The general
line of thought in those comments is that NERC is imposing itself into the local planning process in
violation of existing statutes. The proposed solution allows for input and participation at every step of
the process by local jurisdictional authorities. In Order 693, FERC clearly stated that it has jurisdiction
over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO
to write standards and requirements to address all aspects of BES operations and reliability in support
of these goals. The proposed footnote ‘b’ solution acknowledges these facts and the SDT believes it is
an appropriate response to FERC directives on this matter.
Many commenters questioned the use of a stakeholder process at all. Those commenters expressed
the opinion that the FERC Order did not mandate the use of the stakeholder process. The SDT used the
Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard;
not because it contained a stakeholder process, but because the process was not well defined, did not
include quantitative and qualitative criteria for allowing curtailment of Firm Demand and did not assure
that BES reliability would be maintained. The balloted draft added detail and specificity to the already
approved approach, in order to address these concerns.
A few commenters indicated disagreement with the 75 MW limit the proposed standards place on the
amount of Non-Consequential Load that can be planned to be shed for a single contingency, with some
commenters indicating that the limit should be higher than the proposed limit while others indicated
that planning to shed load was inconsistent with planning for a reliable bulk power system.
Finally, some commenters continue to question facets of the proposed TPL-001-2a standard previously
approved by the industry and the NERC Board of Trustees. These commenters are questioning the
application (or non-application) of footnote 12 for various planning events. . The SAR for this project
took the approved TPL-001-2 as the starting point for the specific discussion of footnote ‘b’/12 and
does not allow for review of previously approved applications of the footnote, which were developed
and reached ballot pool consensus and Board approval in a previous effort.
All comments submitted may be reviewed in their original format on the standard’s project page.
If you feel that your comment has been overlooked, please let us know immediately. Our goal is to give
every comment serious consideration in this process! If you feel there has been an error or omission,
you can contact the Vice President and Director of Standards, Mark Lauby, at 404-446-2560 or at
[email protected]. In addition, there is a NERC Reliability Standards Appeals Process.1

1

The appeals process is in the Standard Processes Manual: http://www.nerc.com/files/Appendix_3A_StandardsProcessesManual_20120131.pdf

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

2

Index to Questions, Comments, and Responses
1.

Do you agree with changes made to the body of the footnote? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comment ....................................................................11

2.

Do you agree with the changes contained in Section II of Attachment 1? If you do not support
these changes or you agree in general but feel that alternative language would be more
appropriate, please provide specific suggestions in your comments ..............................................28

3.

Do you agree with changes contained in Section III of Attachment 1? If you do not support these
changes or you agree in general but feel that alternative language would be more appropriate,
please provide specific suggestions in your comments. ..................................................................36

4.

If you have any other comments on this Standard that you haven’t already mentioned above, and
that are not simply reiterating previous comments that the SDT has already responded to, please
provide them here:...........................................................................................................................45

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

3

The Industry Segments are:
1 — Transmission Owners
2 — RTOs, ISOs
3 — Load-serving Entities
4 — Transmission-dependent Utilities
5 — Electric Generators
6 — Electricity Brokers, Aggregators, and Marketers
7 — Large Electricity End Users
8 — Small Electricity End Users
9 — Federal, State, Provincial Regulatory or other Government Entities
10 — Regional Reliability Organizations, Regional Entities

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1.

Group

Jim Kelley

Additional Member

Additional Organization

SERC EC Planning Standards Subcommittee

Ameren Services Company

SERC

1

2. Charles Long

Entergy

SERC

1

3. Edin Habibovic

Entergy

SERC

1

4. James Manning

NC Electric Membership Corporation SERC

1

5. Philip Kleckley

SC Electric & Gas

SERC

1

6. Shih-Min Hsu

Southern Company Service

SERC

1

7. Darrin Church

TVA

SERC

1

8. Bob Jones

Southern Company Service

SERC

1

9. Pat Huntley

SERC Reliability Corporation

SERC

10

Group

Guy Zito

3

4

5

6

7

8

9

10

X

Region Segment Selection

1. John Sullivan

2.

X

2

Northeast Power Coordinating Council

X

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

Additional Member

Additional Organization

Alan Adamson

New York State Reliability Council, LLC NPCC 10

2.

Carmen Agavriloai

Independent Electricity System Operator NPCC 2

3.

Greg Campoli

New York Independent System Operator NPCC 2

4.

Sylvain Clermont

Hydro-Quebec TransEnergie

NPCC 1

5.

Wayne Sipperly

New York Power Authority

NPCC 5

6.

Gerry Dunbar

Northeast Power Coordinating Council

NPCC 10

7.

Mike Garton

Dominion Resources Services, Inc.

NPCC 5

8.

Kathleen Goodman

ISO - New England

NPCC 2

9.

Donald Weaver

New Brunswick System Operator

NPCC 2

10. David Kiguel

Hydro One Networks Inc.

NPCC 1

11. Christina Loncz

PSEG Power LLC

NPCC 5

12. Randy MacDonald

New Brunswick Power Transmission

NPCC 9

13. Bruce Metruck

New York Power Authority

NPCC 6

14. Silvia Parada Mitchell NextEra Energy, LLC

NPCC 5

15. Lee Pedowicz

Northeast Power Coordinating Council

NPCC 10

16. Robert Pellegrini

The United Illuminating Company

NPCC 1

17. Si-Truc Phan

Hydro-Quebec TransEnergie

NPCC 1

18. David Ramkalawan

Ontario Power Generation, Inc.

NPCC 5

19. Brian Robinson

Utility Services

NPCC 8

Group

Southwest Power Pool Reliability Standards
Development Group

Jonathan Hayes

3

4

5

6

7

Region Segment Selection

1.

3.

2

X

X

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1. Jonathan Hayes

Southwest Power Pool

SPP

NA

2. Robert Rhodes

Southwest Power Pool

SPP

NA

3. Tiffany Lake

Westar Energy

SPP

1, 3, 5, 6

4. Don Taylor

Westar Energy

SPP

1, 3, 5, 6

5. Stephen McGie

City of Coffeyville

SPP

NA

6. Valerie Pinamonti

American Electric Power SPP

4.

Group

Jamison Dye

1, 3, 5

Bonneville Power Administration

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X

5

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

5.

Group

Terry L. Blackwell

Santee Cooper

2

3

X

X

X

X

4

5

6

X

X

X

X

7

Additional Member Additional Organization Region Segment Selection
1. Vicky Budreau

Santee Cooper

SERC

1

2. Jim Peterson

Santee Cooper

SERC

1

3. Chris Jimenez

Santee Cooper

SERC

1

4. Chris Wagner

Santee Cooper

5. Cindy Corson

Santee Cooper

6. Mike Coker

Santee Cooper

SERC

1

7. Rene' Free

Santee Cooper

SERC

1

8. Tom Abrams

Santee Cooper

SERC

1

9. Rick Thornton

Santee Cooper

SERC

1

6.

Group

1
1

paul haase

seattle city light

X

Additional Member Additional Organization Region Segment Selection
1. pawel krupa

seattle city light

WECC 1

2. dana wheelock

seattle city light

WECC 3

3. hao li

seattle city light

WECC 4

4. mike haynes

seattle city light

WECC 5

5. dennis sismaet

seattle city light

WECC 6

7.

Group

Ben Engelby

Additional
Member

X

ACES Standards Collaborators
Additional Organization

Region

Segment
Selection

1. John Shaver

Arizona Electric Power Cooperative Inc./Southwest Transmission
Cooperative Inc.

WECC 1, 4, 5

2. Shari Heino

Brazos Electric Power Cooperative, Inc.

ERCOT 1, 5

3. Amber Anderson

East Kentucky Power Cooperative

SERC

1, 3, 5

4. Megan Wagner

Sunflower Electric Power Corporation

SPP

1

5. Bill Hutchison

Southern Illinois Power Cooperative

SERC

1

6. Scott Brame

North Carolina Electric Membership Corporation

RFC

1, 3, 4, 5

8.

Group

WILL SMITH

MRO NSRF

X

X

X

X

X

X

Additional Member Additional Organization Region Segment Selection
1.

MAHMOOD SAFI

OPPD

MRO

1, 3, 5, 6

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

6

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

2.

TOM BREENE

WPS

MRO

3, 4, 5, 6

3.

JODI JENSON

WAPA

MRO

1, 6

4.

KEN GOLDSMITH

ALTW

MRO

4

5.

DAVE RUDPOLPH BEPC

MRO

1, 3, 5, 6

6.

ERIC RUSKAMP

MRO

1, 3, 5, 6

7.

JOE DEPOORTER MGE

MRO

3, 4, 5, 6

8.

SCOTT NICKELS

RPU

MRO

4

9.

TERRY HARBOUR MEC

MRO

1, 3, 5, 6

LES

10. MARIE KNOX

MISO

MRO

2

11. LEE KITTELSON

OTP

MRO

1, 3, 5

12. SCOTT BOS

MPW

MRO

1, 3, 5, 6

13. TONY EDDLEMAN NPPD

MRO

1, 3, 5

14. MIKE BRYTOWSKI GRE

MRO

1, 3, 5, 6

15. DAN INMAN

MPC

MRO

1, 3, 5, 6

9.

Greg Rowland

Group

Duke Energy

X

2

3

X

4

5

X

6

7

X

Additional Member Additional Organization Region Segment Selection
1. Doug Hils

Duke Energy

RFC

1

2. Lee Schuster

Duke Energy

FRCC

3

3. Dale Goodwine

Duke Energy

SERC

5

4. Greg Cecil

Duke Energy

RFC

6

10.

Group

Sasa Maljukan

Additional Member
1. David Kiguel

Hydro One Networks Inc.

X

Additional Organization Region Segment Selection
Hydro One Networks Inc. NPCC 1

2. Hamid Hamadanizadeh Hydro One Networks Inc. NPCC 1

11.

Group

John Allen

Additional Member

Additional Organization

Iberdrola USA
Region Segment Selection

1. Joseph Turano

Central Maine Power

2. Raymond Kinney

New York State Electric & Gas NPCC 1

3. David Conroy

Central Maine Power

12.

Group

Michael Jones

Additional Member

X

NPCC 1
NPCC 1

National Grid

Additional Organization

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X

X

Region Segment Selection

7

8

9

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

1. Michael Schiavone

13.
14.
15.

Individual

Chris Pink

Individual

Tim Ponseti, VP

Individual

Diane Barney

Tri-State G&T
TVA Transmission Reliability Engineering
and Controls

X

17.

Individual

Shih-Min Hsu

Southern Company

18.

Individual

Frederick R Plett

Massachusetts Attorney General

19.

Individual

Thad Ness

American Electric Power

X

20.

Individual

Oliver Burke

Entergy Services, Inc. (Transmission)

X

Individual
22. Individual

Chris de Graffenried
David Jendras

Consolidated Edison Co. of NY, Inc.
Ameren

23.

Individual

Nazra Gladu

Manitoba Hydro

24.

Individual

David Wang

SDG&E

25.

Individual

Bob Easton

Individual
Individual

Kenn Backholm
Steve Alexxanderson
P.E.

WAPA-RMR
Public Utility District No.1 of Snohomish
County

28.

Individual

Milorad Papic

Idaho Power Company

29.

Individual

Russ Schneider

Flathead Electric Cooperative, Inc.

30.

Individual

Cheryl Moseley

Electric Reliability Council of Texas, Inc.

31.

Individual

Jim Cyrulewski

JDRJC Associates LLC

32.

Individual

Kathleen Goodman

ISO New England Inc

33.

Individual

John Collins

Platte River Power Authority

X

34.

Individual

Keith Morisette

Tacoma Power

X

27.

5

6

7

8

9

X

X
X
X

Lloyd A. Linke

26.

4

X

Individual

21.

3

Niagara Mohawk (A National Grid Company) NPCC 3

NARUC
Western Area Power Administration Transmission Owner

16.

2

X
X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X
X

X

X

X

X

X

X

X

X

X

X

X

X

X

X

X
X

Central Lincoln

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

X
X
X
X
X

X

X

X

8

10

Group/Individual

Commenter

Organization

Registered Ballot Body Segment
1

35.

Donald Weaver

Individual

Michiko Sell

New Brunswick System Operator
Public Utility District No. 2 of Grant County,
WA

Individual
38. Individual

Michael Moltane
Mark Westendorf

ITC
MISO

X

39.

Individual

Michael R. Lombardi

Northeast Utilities

40.

Individual

Patricia Robertson

BC Hydro

X
X

41.

Individual

Teresa Czyz

Georgia Transmission Corp.

X

42.

Individual

Si Truc PHAN

Hydro-Quebec TransEnergie

X

43.

Individual

Clay Young

SCE&G

X

44.

Individual

Michael Falvo

Independent Electricity System Operator

45.

Individual

Brett Holland

Kansas City Power & Light

X

46.

Individual

Oncor Electric Delivery Company LLC

X

Individual

Darryl Curtis
Vijayraghavan
bangalore

48.

Individual

Alice Ireland

Xcel Energy

X

49.

Individual

Tony Kroskey

Brazos Electric Power Cooperative, Inc.

X

37.

47.

3

4

5

6

7

X

Individual

36.

2

X

X

X

X

X

X
X

X
X

X
X

X

X

X

X

X

X

X

X

X

X

X
Pacific gas and Electric Comapny

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

9

8

9

10

If you support the comments submitted by another entity and would like to indicate you agree with their comments, please select
"agree" below and enter the entity's name in the comment section (please provide the name of the organization, trade association,
group, or committee, rather than the name of the individual submitter).

Summary Consideration: The SDT thanks you for following the instructions and lessening the SDT workload. Your support for
comments submitted by another entity will be noted accordingly.
Organization

Supporting Comments of “Entity Name”

Flathead Electric Cooperative, Inc.

We support the comments submitted by Central Lincoln

JDRJC Associates LLC

Midwest ISO

Kansas City Power & Light

SPP

Brazos Electric Power Cooperative, Inc.

ACES Power Marketing

ITC

MISO

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

10

1.

Do you agree with changes made to the body of the footnote? If you do not support these changes or you agree in general but
feel that alternative language would be more appropriate, please provide specific suggestions in your comment

Summary Consideration: In general, the SDT has responded to the individual comments and there are no technical changes proposed
to the standards as a result of comments. However, the SDT has responded to a request from Canadian entities to make a change to the
main body of the footnotes to address specific jurisdictional concerns for non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under
footnote ‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
While the revision for non-US registered entities qualifies as a significant change to the standards, the Standards Committee has decided
that since the indicated change was simply for a jurisdictional issue, and did not change the technical content or intent of the standard,
that this project can be moved forward to the recirculation ballot stage.
Organization

Yes or No

Northeast Power Coordinating Council

No

Question 1 Comment
Dropping load generally should not be endorsed, but it is recognized that
there are special situations where it cannot be avoided. If a regulator
responsible for load is comfortable with greater than 75MW being
dropped in a rare situation, there should not be a requirement to build
out of the situation.
Provided there is no widespread, adverse effect on the reliability of the
interconnected BES, the effect of a interruption on customers is under
the purview of the applicable regulatory authority that is responsible for
local transmission and retail service over the load to be curtailed. NERC
must acknowledge that jurisdictional authorities can decide on the
parameters for planning events that do not have an impact on the
reliability of interconnected BES .
There are no limits on non-consequential load loss for Single Contingency

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

11

Organization

Yes or No

Question 1 Comment
P2-2 and P2-3 (HV only), multiple Contingencies P4 and P5 (HV only), and
P6 and P7. Footnote 12 allows limited non-consequential load loss for
single contingency P1, Multiple Contingency P3. Non-consequential load
loss is not allowed for P2-2 and P2-3 (EHV), and P4 and P5 (EHV).
Considering the extensive EHV Facilities in the Canadian regions of NPCC,
it is not reasonable to accept some non-consequential load loss for
single contingency P1 and P2-3, and then deny it for Multiple
Contingency categories P4 and P5 which are statistically less frequent
than the former. Also, the Multiple Contingency P7 (for which there is no
limit on non-consequential load loss) is more frequent than P2-3, P4 and
P5. This technical irregularity must be reviewed and addressed. This
comment was submitted for the last posting.

Response: The SDT has previously pointed out that building is not the sole source of remedy for the situation. Examples of other
allowable actions were specifically provided in the January 8, 2013 webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf ). No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. As shown by
this approval, the SDT and the industry disagree that there is a technical irregularity in Table 1. The Board of Trustees has also
previously approved this proposed standard. Discussions on the applicability of footnote 12 in that standard were held during
Project 2006-02 and are not part of this proceeding. No change made.
Public Utility District No. 2 of Grant
County, WA

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

GCPD abstains from voting on the revisions to footnote "b" in TPL-002-1c
and the corresponding footnote 12 of TPL-001-2. GCPD is concerned that
the revised language oversteps the bounds of the "reliability standard"
12

Organization

Yes or No

Question 1 Comment
definition under Section 215 of the Federal Power Act and into customer
service issues that are better served by, and under the jurisdiction of,
state and local utility boards and commissions. However, in the spirit of
moving this process forward, GCPD did not vote against the revised
footnotes.

Santee Cooper

No

Santee Cooper will abstain from voting on the revisions to footnote "b" in
TPL-002-1c and the corresponding footnote 12 of TPL-001-2. Santee
Cooper is concerned that the revised language oversteps the bounds of
the "reliability standard" definition under Section 215 of the Federal
power Act and into customer service issues that are better served by,
and under the jurisdiction of, state and local utility boards and
commissions. However, in the spirit of moving this process forward,
Santee Cooper will not vote against the revised footnotes.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Hydro One Networks Inc.

No

In this comment period Hydro One would like to reiterate its initial
comments.
Hydro One disagrees with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread, adverse effect on the reliability of the interconnected
bulk electric system, the effect on customers of a firm demand
interruption is the responsibility of the applicable regulatory authority or
its delegated agencies responsible for local transmission and retail

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

13

Organization

Yes or No

Question 1 Comment
service over the load to be curtailed.
If it is decided to proceed with the 75 MW or any other value, we
propose replacing the sentence, in the footnote and in attachment one,
section III that reads:”In no case can the planned Non-Consequential
Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a non-US Registered Entity should be
determined by the applicable Regulatory Authority or Governmental
Authority or its delegated agency in that is responsible for retail electric
service issues in that jurisdiction.”

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
NARUC

No

As stated before, if there is no reliability threat to the bulk system there
is no need for the 75 MW limit on the anticipated amount of load to be
shed. As long as the regulator responsible for the retail load subject to
being shed is notified of the situation, the situation can be appropriately
addressed at the local level.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these
orders mandate the ERO to write standards and requirements to address all aspects of BES operations and reliability in support of
these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC
directives on this matter. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

14

Organization

Yes or No

SCE&G

No

Question 1 Comment
Comments previously submitted.

Response: Thank you for following the guidelines. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Independent Electricity System Operator

No

Please note that the Independent Electricity System Operator (IESO), an
RTO/ISO registered under Industry Segment 2, has filed an appeal with
respect to NERC’s response to our similar comments submitted to the
previous ballot on this project.
We disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard. Provided there is
no widespread adverse effect on the reliability of the interconnected
bulk power system, the effect on customers of a firm demand
interruption is the responsibility of the applicable regulatory authority or
its agencies responsible for local transmission and retail service over the
load to be curtailed.
To recognize NERC’s role as the ERO for Ontario and the Memorandum of
Understanding between NERC and the Ontario Energy Board, the IESO
proposed replacing the sentence, in the footnote and in attachment one,
section III that reads:”In no case can the planned Non-Consequential
Load Loss under footnote 12 exceed 75 MW.” with “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 under footnote 12 for a Registered Entity that is a Canadian
Entity (or a Mexican Entity) should be implemented in a manner that is
consistent with/or under the direction of the Applicable Governmental
Authority or its agency in Canada (or Mexico).Under this language, both
the amount of non-consequential load loss, and the process under which
that amount was arrived at, including stakeholder consultations, would
be determined by the relevant Canadian jurisdiction, in this case Ontario.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

15

Organization

Yes or No

Question 1 Comment
This change will make the standard acceptable in Ontario’s legislative
framework, in which NERC standards come into force automatically
unless, by order of the Ontario Energy Board, a standard is stayed and
remanded back to NERC for further consideration.
The responses to the IESO’s comments in the previous ballot were
inaccurate as to this key feature of the Ontario reliability framework, as
addressed in the IESO appeal. An alternate solution to this issue, which
would o be consistent with the intent of the responses to the IESO
comments on the previous ballot, o respect the Ontario reliability
framework, and o resolve the IESO January 9, 2013 appeal; and is
appropriate given that these changes are being driven by a U.S. FERC
remand order to NERC, would be to make the following highlighted
clarifications to footnotes ‘b’ and 12:With respect to Standard TPL-002-1c
- footnote ‘b’ b) An objective of the planning process is to minimize the
likelihood and magnitude of interruption of firm transfers or Firm
Demand following Contingency events. Curtailment of firm transfers is
allowed 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 the shedding of any Firm Demand. It is recognized that Firm For
purposes of this footnote, the following are not counted as Firm Demand
will be interrupted if itt is: (1) Demand directly served by the Elements
removed from service as a result of the Contingency, or and (2)
Interruptible Demand or Demand-Side Management Load. In limited
circumstances, Firm Demand may be interrupted throughout the
planning horizon to ensure that BES performance requirements are met.
However, for U.S. registered entities when interruption of Firm Demand
is utilized within the Near-Term Transmission Planning Horizon to
address BES performance requirements, such interruption is limited to

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

16

Organization

Yes or No

Question 1 Comment
circumstances where the use of Firm Demand interruption meets the
conditions shown in Attachment 1. In no case can the planned Firm
Demand interruption under footnote ‘b’ exceed 75 MW for U.S.
registered entities. With respect to Standard TPL-001-2a - footnote
12:12. An objective of the planning process is to minimize the likelihood
and magnitude of Non-Consequential Load Loss following Contingency
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, for U.S. registered entities
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 U.S. registered entities.

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of Texas, Inc.

No

See response to question 4.

No

1. In the last submittal for comments, the following comment was made:
It was not clear how transmission projects with long lead times (such as
T-lines) would be handled by “Footnote b.” In other words, it is not clear

Response: See response to Q4.
Tri-State G&T

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

17

Organization

Yes or No

Question 1 Comment
if it is acceptable for a TP to plan for shedding Firm Demand in the Near
Term Planning Horizon without meeting the conditions shown in
“Attachment 1” when a mitigating project is planned that cannot be
constructed in the Near Term Planning Horizon. The Standard Drafting
Team (SDT) provided the following response: Any instance of proposed
load shed for a single Contingency situation in a Planning Assessment
must meet the conditions of footnote ‘b.’ No Change made. From the
above comments, we believe there is a situation where the Bulk Electric
System (BES) reliability is compromised while stakeholder process
proceeds.

Response: This standard ensures these items are addressed in planning prior to them becoming an issue in operations so the SDT
believes that BES reliability is not being compromised. No change made.
Western Area Power Administration Transmission Owner

No

While Western generally agrees with the proposed modification to
footnote b, Western does not support the 75 MW threshold and
Attachment 1 Stakeholer process. The 75 MW threshold seems to low
and if a threshold it needed the drafting team should consider using a
300 MW threshold similar to that used in CIP-002, EOP-004, DOE OE-417
reporting, and NERC event analysis process.
The stakeholder process seems to be duplicative, considering there FERC
Order 890 planning process.

WAPA-RMR

No

While Western agrees in general with what is proposed in Footnote b; I
do not agree with stipluating 2 requirements in the proposed Footnote b:
The 75 MW load threshold; the Attachment 1 Stakeholder process. The
75 MW seems low and NERC should condsider using a 300 MW threshold
similar to that used in CIP-002 and EOP-004 requirements.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to 75 MW as a
reasonable limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The SDT used the
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

18

Organization

Yes or No

Question 1 Comment

Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it contained a
stakeholder process, but because the process was not well defined, did not include quantitative and qualitative criteria for allowing
curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail and
specificity to the already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in Reliability
Standards and both mechanisms have been used before. No change made.
The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to allow an
entity to use an existing process as long as it meets the requirements shown in Attachment 1. No change made.
Massachusetts Attorney General

No

The SDT ignored a lot of feedback concerning the inappropriateness of a
75 MW threshold. IT remains inappropriate and an appropriate level
should be decided by local stakeholder processes.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The proposed solution allows
for input and participation at every step of the process by local jurisdictional authorities. In Order 693, FERC clearly stated that it has
jurisdiction over matters that involve BES operations and reliability. Furthermore, these orders mandate the ERO to write standards
and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote ‘b’
solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Entergy Services, Inc. (Transmission)

No

Attachment 1 is overly burdensome and concerns local reliability issues
better left to local regulators.
A planned or unplanned loss of 25 MW is inconsequential to the
reliability of the BES. The footnote could be simplified to exclude
attachment 1 as follows: An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following Contingency planning events. In limited circumstances, NonConsequential 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

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

19

Organization

Yes or No

Question 1 Comment
performance requirements, such interruption is limited to 25 MW and
notice must be given to applicable regulatory authorities or governing
bodies responsible for retail electric service issues within 30 days of the
completion of the assessment which includes the use of footnote 12.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that involve BES operations and reliability and the proposed
footnote ‘b’ solution acknowledges that fact and is an appropriate response to subsequent FERC directives on this matter. No change
made.
The SDT disagrees that Attachment 1 is overly burdensome as it simply addresses items that would be part of a Transmission
Planner’s normal workload. No change made.
As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The current
proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to be
supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Consolidated Edison Co. of NY, Inc.

No

Planned interruptions of Firm Demand in response to a Single
Contingency (as directed in Footnote b of TPL-002 Table 1, and Footnote
12 of TPL-001-2), is not an acceptable corrective action to mitigate
reliability issues on the BES system. The Interconnected System should
be designed and operated with enough transfer capacity to be able to
withstand, at a minimum, a single contingency event without service
interruptions to customer load. Systems must be designed and operated
so that the impact of any single contingency can be mitigated by redispatching available system resources without the need to implement
load shedding.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

20

Organization

Yes or No

SDG&E

No

Question 1 Comment
Table 1, footnote b of TPL-002 allows the use of load shedding for the
loss of a single element (Category B) under certain circumstances. SDG&E
has been against the proposed changes because of the addition of a
stakeholder process that allows outside entities to make reliability
decisions which we would be held accountable for.

Response: The SDT believes that the described process allows for open and transparent discussion of the potential use of footnote
‘b’ in the planning environment and disagrees that anything in the proposed footnote provides outside entities with the ability to
make reliability decisions. No change made.
Platte River Power Authority

No

Disagree with no change to the 75 MW threshold, but agree with the
minor changes that were made since last posting. I request your
consideration of a 300 MW threshold similar to that used in CIP-002 and
EOP-004. Since there is a directive for some threshold, and in an attempt
to reduce the likelihood of over-burdening smaller communities, the 300
MW level would be a more reasonable threshold for the BES.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. No change made.
ISO New England Inc

No

There are jurisdictional issues with the footnote and attachment as
written. These will be described in further detail throughout this
document.
The footnote itself states, “An objective of the planning process is to
minimize the likelihood and magnitude of Non-Consequential Load Loss
following planning events.” A standard should not have requirements
described as objectives, this language is extremely subjective.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

21

Organization

Yes or No

Question 1 Comment

of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
The SDT does not believe that the stated objective serves as a requirement. No change made.
MISO

No

ITC

MISO does not object to the changes made to the body of the footnote
since the previous draft.
However, as a general matter, MISO cannot support the current language
of Footnote 12. Because the intent of the TPL standards is not to rely on
non-consequential firm load shedding after a single contingency event,
MISO does not agree that footnote b in NERC TPL-002-1 and/or footnote
12 in TPL-001-2 should be included in these standards.

JDRJC Associates LLC

Nonetheless, if these footnotes are included, MISO agrees that there
should be some limitation on how much firm load shed is allowed under
these footnotes and would not object to the proposed 75 MW level if the
footnotes are included.
Response: Thank you for your support.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Northeast Utilities

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Northeast Utilities does not support the use of non-consequential
demand interruption throughout the planning horizon. Even with the 75
MW limit, NU believes that this language seems to encourage
operational workarounds and adds burdens for operators of the system.
Lastly, NU believes this use of non-consequential load loss during the
planning horizon is not consistent with planning a highly reliable bulk

22

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Yes or No

Question 1 Comment
electric system and thus does not support non-consequential load loss
for planning purposes.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.
Hydro-Quebec TransEnergie

No

Hydro-Québec TransÉnergie (HQT) remains unconvinced that a MW
threshold needs to be part of footnote 12. This is not a BES reliability
issue but only a matter of service continuity to be addressed by
TO/PA/RC with local regulatory authorities.

Response: The SDT Believes that the FERC Orders made it clear that the concept of dropping Non-Consequential Load for a N-1
Contingency must include MW thresholds. The SDT has made a change to the main body of the footnotes to address the concerns of
non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Pacific gas and Electric Comapny

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We do not agree with the imposition of a maximum limit on the amount
of planned Firm Demand interruption under footnote b. This addition is
overly prescriptive, unnecessary, and can have unintended consequences
on service reliability. Assigning a fixed “not to exceed” number of MW in
a continent-wide standard is overly prescriptive. A single number cannot
account for variation even within one BA Area. A fixed maximum number
of MW for Non-Consequential Load Loss under Footnote b in TPL-002
(and footnote 12 in TPL-001-3) is not necessary. The first sentence of this
footnote states, “[a]n objective of the planning process should be to
minimize the likelihood and magnitude of interruption of firm transfers
or Firm Demand following Contingency events”. It is clear that the spirit
23

Organization

Yes or No

Question 1 Comment
of the TPL Standard is to minimize the likelihood and magnitude of Firm
Demand interruption. Adding a fix maximum number of MW would
seem unnecessary at best. At worst, it could have unintended
consequences. Without a fixed maximum Non-Consequential Load Loss,
the Transmission Planner understands that the objective is to minimize
the magnitude of the planned interruption under footnote b (TPL-001-3,
footnote 12). Adding a maximum number of MW of planned Firm
Demand loss could have the effect of giving “safe harbor” to allow
planned loss of that amount of load under Footnote b. The Transmission
Planner may now have more difficulty in avoiding Non-Consequential
Firm Demand Loss that is less than the “not to exceed” amount.

Response: The development of a standard that allowed for the use of footnote ‘b’ without quantifiable criteria was not acceptable to
FERC as shown in the Remand Order. There is no ‘safe harbor’ up to the identified limit since it will be discussed in an open and
transparent stakeholder process that includes applicable regulators. No change made.
ACES Standards Collaborators

Yes

Brazos

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) We continue to disagree with the 75 MW capacity limit threshold.
There is no need for a 75 MW cap because registered entities and locallevel policy makers are in the best position to determine an appropriate
capacity limit, as stated in the FERC order and in previous feedback.
However, if the drafting team decides to move forward with a cap, we
suggest using a cap that would reflect all data points from the Section
1600 data request to be under the threshold. The findings to the data
request contained a data point at 75.2 MW, which would be over the
proposed threshold. We understand this data point, in essence, has
been omitted because the use of non-consequential load shedding for
the 75.2 MW data point is expected to terminate soon. If the drafting
team intends to use the data that represents the actual usage of
footnote ‘b’ by planning coordinators, then the team should take into
account the highest data point and adjust the threshold to at least 76
MW regardless of the length of time the data point is needed. Again,
24

Organization

Yes or No

Question 1 Comment
local decision makers are better equipped to make this type of
determination.
(2) However, in the spirit of moving forward with this project we will
support the changes and thank the drafting team for their efforts.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. In
Order 693, FERC clearly stated that it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these
orders mandate the ERO to write standards and requirements to address all aspects of BES operations and reliability in support of
these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC
directives on this matter. The SDT established the limit based on the results of the Section 1600 data request which clearly pointed
to a 75 MW limit. While the SDT considered a higher limit value, the data collected does not justify such an action. No change made.
Thank you for your support.
Georgia Transmission Corp.

Yes

Since this question refers to both footnote b (TPL-002-1c) and footnote
12 (TPL-001-2a), and the changes to the footnotes are not identical, the
question should be split into two.
Regarding footnote b: An excerpt from footnote b reads “For purposes of
this footnote, the following are not counted as Firm Demand (1) Demand
directly served by the Elements removed from service as a result of the
Contingency ...” However, what is being described is in fact Firm
Demand (That portion of the Demand that a power supplier is obligated
to provide except when system reliability is threatened or during
emergency conditions) that is Consequential Load Loss (All Load that is
no longer served by the Transmission system as a result of Transmission
Facilities being removed from service by a Protection System operation
designed to isolate the fault.). Therefore, why not use the terms
Consequential Load Loss and Non-Consequential Load Loss?
Regarding footnote 12: The replacing the NERC defined “Contingency”
event with the undefined “planning” event necessitates a new definition.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

25

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Yes or No

Question 1 Comment
The intent of the change is unclear.

Response: The issue is one of timing. The indicated terms are part of the proposed TPL-001-2 solution and were not in existence
when TPL-002-1 was developed. Since the SDT cannot control how FERC will respond to the proposed solutions to this project, it is
possible that TPL-002-1 could be approved prior to TPL-001-2. This would create considerable confusion as to the use of these terms.
Therefore, the SDT wrote the proposed solutions separately. No change made.
The wording change now makes the terminology consistent in both Table 1 and the text. No change made.
Manitoba Hydro

Yes

SERC EC Planning Standards Subcommittee

Yes

Southwest Power Pool Reliability
Standards Development Group

Yes

Manitoba Hydro agrees that the changes add clarity to the footnote.

Kansas City Power & Light

Bonneville Power Administration

Yes

MRO NSRF

Yes

Duke Energy

Yes

TVA Transmission Reliability Engineering
and Controls

Yes

Southern Company

Yes

American Electric Power

Yes

Ameren

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

26

Organization

Yes or No

Idaho Power Company

Yes

Tacoma Power

Yes

ITC

Yes

Oncor Electric Delivery Company LLC

Yes

Question 1 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

27

2.

Do you agree with the changes contained in Section II of Attachment 1? If you do not support these changes or you agree in
general but feel that alternative language would be more appropriate, please provide specific suggestions in your comments

Summary Consideration: The SDT has responded to the individual comments and there are no changes proposed to the standards as a
result of comments.
Organization

Yes or No

ACES Standards Collaborators

No

Brazos

Question 2 Comment
(1) Thank you for making the changes to Section II of Attachment 1. We believe the
modification of removing “assessments” and replacing it with “explanation”
provides more flexibility regarding how a registered entity can demonstrate the
impacts the health, safety and welfare of the community.
(2) However, we still believe that the word “alleviate” in bullet 5 requires the same
actions as the word “mitigate.” There are instances where no action is required
based on a variety of factors. We recommend the following: “Future plans, if
necessary, to mitigate/alleviate the need for Non-Consequential Load Loss under
footnote 12, unless a determination was made not to mitigate/alleviate, then an
explanation why.”

Response: Thank you for your support.
This is an information section and not a requirement for a more permanent solution. Therefore, if there is no plan to alleviate then
an entity simply documents that fact. No change made.
MRO NSRF

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

The drafting team over specified the Section II stakeholder information process and
continues to disregard comments that item 2b be removed from several utilities
over several footnote “b” revisions. The goal of Attachment 1 as stated by the
drafting team chair was to place “meaningful” parameters around footnote b. The
words in 2b on “health, safety, and welfare” are beyond the scope of NERC
standards, and are not defined sufficiently in the standard to make the

28

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Yes or No

Question 2 Comment
requirement meaningful. The NSRF recommends that if the drafting team doesn’t
eliminate 2b, they delete the words “on the health, safety, and welfare of the
community” as going beyond NERC jurisdiction, FERC directives, and the SAR. The
drafting team response that similar words exist in another standard is not a reason
to the ambiguous words in the TPL Attachment 1.

Response: The SDT did not justify the retention of the subject phrase simply because similar words exist in another standard but
because the burden and intent of the phrase in footnote ‘b’ is consistent with what entities are required to do in that other standard
(the phrase is included in EOP-001 as part of a description of Load curtailment in Attachment 1 of EOP-001, which describes elements
for consideration in developing emergency plans). The SDT believes that the changes made in this posting clarify the intent of this
requirement. No change made.
Hydro One Networks Inc.

No

As previously stated, we believe that the process presented in Section II is overly
prescriptive.
If a section that prescribes the information requirements for a stakeholder process
is required, then for non-US entities this section should simply require that the
process information requirements must be in accordance with the requirements of
the applicable Regulatory Authority or Governmental Authority or its delegated
agency that is responsible for local transmission and retail service in that
jurisdiction.

Independent Electricity System
Operator

No

No. The process presented in Section II is overly prescriptive.
If a section that prescribes the information requirements for a stakeholder process
is required, then for Canadian entities this section should simply state that any
threshold should be established in a manner consistent with other service levels
that apply to local transmission and retail service for the load to be curtailed, for
the reasons described in Q1.

Response: The SDT has made a change to the main body of the footnotes to address the concerns of non-US registered entities.
TPL-001-2a and TPL-002-1c (main body of the footnote) - In no case can the planned Firm Demand interruption under footnote
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

29

Organization

Yes or No

Question 2 Comment

‘b’ exceed 75 MW for US registered entities. The amount of planned Non-Consequential 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.
Tri-State G&T

No

2. As stated previously, NERC Functional Model definitions for Planning Authorities
and Transmission Planners do not include the types of activities being proposed in
“Attachment 1.” As written, this standard mandates functions on functional entities
that are outside those defined by the NERC Functional Model. The SDT
acknowledged this by stating that “the NERC Functional Model is a guideline for
activities required of cited functional entities.”As such, we still believe that
obligations should not be required of entities outside of the NERC Functional Model
descriptions.

Response: The SDT stands by its previous response to this comment posted for the comment period ending November 19, 2012.
SCE&G

No

Comments previously submitted.

Response: Thank you for following the guidelines. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of
Texas, Inc.

No

See response to question 4.

No

Attachment 1 is overly burdensome and unnecessary.

Response: See response to Q4.
Entergy Services, Inc.
(Transmission)

Response: The SDT believes that Attachment 1 is an appropriate response to the FERC Orders. Without specifics the SDT is unable to
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

30

Organization

Yes or No

Question 2 Comment

provide a more detailed response to your concerns. No change made.
Manitoba Hydro

No

Any assessment or explanation is only speculation. Is the requirement any
different?
Item 5 raises an expectation that footnote 12 can only be used on an interim bases
- this should be clarified.

Response: The SDT believes that the changes made in this posting clarify the intent of this requirement. No change made.
The SDT believes that, in general, the use of footnote ‘b’ to meet TPL performance requirements should be an interim solution.
However, in certain circumstances, the SDT realizes that the solution may be permanent. The SDT does not believe that the wording
only allows for interim use. If the solution is to be permanent, then that information should be disclosed as part of the stakeholder
process. No change made.
ISO New England Inc

No

Section II, 2.a, states that studies must address the estimated number and type of
customers affected by Non-Consequential Load Shedding. The Transmission
Planner in many cases will not be the appropriate entity to address these concerns.
The Transmission Owner, Distribution Provider or Load Serving Entities would be
the appropriate entities to address customer affects.
Explaining effects on the “health, safety, and welfare of the community” is required
under the footnote in Section II, 2.b. The same load could be shed directly as the
consequence of a fault and no such assessment is required. In addition,
Transmission Planners can shed radial load with no assessment of health and
welfare.
In addition to the practical considerations listed, once again here the standard
infringes on Section 215 responsibilities where State authority over the “safety,
adequacy and reliability of the electric system in that state” is mandated. This
section should be deleted.
Section II, requirements 3 and 4 discuss estimating frequency and duration of
Non-Consequential Load Loss based on historical performance. The planning

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

31

Organization

Yes or No

Question 2 Comment
process uses deterministic not probabilistic assessments. This section should be
deleted.

Response: The SDT believes that the indicated information is easily obtained by the Transmission Planner and that, in some cases,
the Transmission Planner may already have this information for other tasks and responsibilities. No change made.
The SDT agrees that such information is not required in other circumstances involving allowed Consequential Load Loss. However,
this situation is different in that it involves Non-Consequential Load Loss. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of footnote ‘b’.
No change made.
MISO

No

ITC
JDRJC Associates LLC

Regarding the use of “explanation” in place of “assessment,” MISO understands
that the purpose of this change is to reduce the need for entities to hire expensive
consultants and to incur other substantial costs in assessing demographic data and
impacts on an affected area. However, as written, this word change potentially
places more of a burden on responsible entities. An assessment is an analysis
performed using available facts and data while an explanation implies full
knowledge. MISO therefore recommends that “assessment” be retained and that a
footnote explaining the meaning of that term be added.
More generally, however, MISO has concerns regarding the use of a stakeholder
process such as the one outlined in Attachment 1 and cannot support the Footnote
or Attachment 1 at this time. Please refer to our comments under Question 4 for a
more detailed description of these concerns.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

32

Organization

Yes or No

Question 2 Comment

Response: The SDT believes that the changes made in this posting clarify the intent of this requirement. No change made.
Please see response to Q4.
Pacific gas and Electric Comapny

No

Suggest removing item 5, “A dispute resolution process for any question or concern
raised in #4 above that is not resolved to the stakeholder’s satisfaction”. Given that
the “applicable regulatory authorities or governing bodies responsible for retail
electric service issues” are only one of the many affected stakeholders, it is unclear
how this dispute resolution process would treat stakeholders with different
concerns. For example, how would such a dispute resolution process take into
account the cost-benefit balance of load loss, which is the responsibility of the
authorities responsible for retail rates, if such an authority is only one of the many
stakeholders subject to dispute resolution?

Response: Bullet #5 does not require specific attributes of the dispute resolution process. The SDT believes that the attributes of the
dispute resolution process should be defined by the entity during the development of the stakeholder process. No change made.
SDG&E

No

Response: Without a specific comment, the SDT is unable to respond.
SERC EC Planning Standards
Subcommittee

Yes

Northeast Power Coordinating
Council

Yes

Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

33

Organization

Yes or No

Bonneville Power
Administration

Yes

Duke Energy

Yes

TVA Transmission Reliability
Engineering and Controls

Yes

Western Area Power
Administration - Transmission
Owner

Yes

Southern Company

Yes

Massachusetts Attorney General

Yes

American Electric Power

Yes

Ameren

Yes

WAPA-RMR

Yes

Idaho Power Company

Yes

Platte River Power Authority

Yes

Tacoma Power

Yes

ITC

Yes

Georgia Transmission Corp.

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Question 2 Comment

34

Organization

Yes or No

Oncor Electric Delivery Company
LLC

Yes

Question 2 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

35

3.

Do you agree with changes contained in Section III of Attachment 1? If you do not support these changes or you agree in general
but feel that alternative language would be more appropriate, please provide specific suggestions in your comments.

Summary Consideration: The SDT has responded to the individual comments and there are no technical changes proposed to the
standards as a result of comments. However, to avoid confusion, the SDT has deleted the duplicative statement in Section III regarding
the 75 MW limit. And, the SDT made a grammatical change in Section III changing ‘does’ to ‘do’ to correct the grammar in the applicable
sentences.
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail electric service issues does not object …”
Organization

Yes or No

MRO NSRF

No

Question 3 Comment
The NSRF believes that the standards drafting team did clarify in the webinar that
the 25 MW and 75 MW footnote “b” values were separate from interruptible load,
and consequential load loss and would not be counted towards the 25 and 75 MW
thresholds. However, the NSRF recommends that Attachment 1 also clearly
contain an explicit statement “the 25 MW and 75 MW footnote “b” values are
separate from consequential load loss, interruptible load, and are not to be
counted towards the 25 MW and 75 MW thresholds.”

Response: The SDT does not believe that this suggestion adds any clarity. No change made.
Hydro One Networks Inc.

No

The process presented in Section III is overly prescriptive and duplicates
information not necessary for its intended purpose.
As stated in Q1, we disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard, and propose alternate
language in our response to Q1.
If this section is required to address a review of the use of footnote 12 to ensure
that there are no wide-spread adverse reliability impacts on the bulk power system,
then it should be limited to the information required for that purpose. Provided
there is local support for the use of Non-Consequential Load Loss under footnote

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

36

Organization

Yes or No

Question 3 Comment
12, only information items 6 and 8 from section II are relevant for this assessmentthe remainder are not required for this section and should be deleted. Items 1 and
2 complicate this section and are unnecessary. They should be replaced by a
phrase such as “for those planning events where the use of footnote 12 is
referenced.” We disagree with the need to submit this information to the ERO for a
determination of whether there are any Adverse Reliability impacts caused by the
use of Non-Consequential Load Loss. This will introduce a new type of review at
the ERO that will create unnecessary delays and burden, and is inconsistent with
(and not required for) all of the other performance requirements in the TPL
standards. Submitting the analysis to the adjacent Planning Coordinators and
Transmission Planners, and any functional entity that requests it, as called for in
requirement R8 of TPL-001-2 should be sufficient.

Response: The SDT does not believe the section is overly prescriptive or duplicative as described below. No change made.
Please see response to Q1.
The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of footnote ‘b’.
If local regulators require additional information they can always request it. While the ERO may not need all of the information in
Section II to perform its Adequate Reliability Impact evaluation, the SDT wanted to minimize the burden on entities by allowing the
submittal of an information package that already existed. The ERO is aware of the proposed responsibility and has accepted this role
if the industry approves. The SDT believes that it is the responsibility of the ERO to assess Adverse Reliability Impacts and is not an
appropriate role for adjacent planners. No change made.
Iberdrola USA

No

See comment to question 4 below.

Electric Reliability Council of
Texas, Inc.

No

See response to question 4.

MISO

No

MISO does not object to the changes made to Section III. However, more generally,
MISO has concerns regarding the use of a stakeholder process such as the one
outlined in Attachment 1 and cannot support the Footnote or Attachment 1 at this

ITC

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

37

Organization

Yes or No

JDRJC Associates LLC

Question 3 Comment
time. Please refer to our comments under Question 4 for a more detailed
description of these concerns.

Response: See response to Q4.
Tri-State G&T

No

3. Previously, it was commented that it is unclear how section III of “Attachment 1”
would be applied to entities that only deliver wholesale electric service and not
retail electric service. The response provided by the SDT stated the following: The
SDT believes that the wholesale customer will be one of the stakeholders included
in the process and any use of footnote must go through the stakeholder process.
No change made. If the wholesale customer is one of the stakeholders, the
standard needs to add wholesale customers into the language as part of
Attachment I. For example, it should read as follows: Coordinator must ensure that
the applicable regulatory authorities, wholesale customers, or governing bodies
responsible for retail electric service issues does not object to the use of Firm
Demand interruptions under footnote ‘b’...

Response: The SDT believes that the planning entity has the best understanding of who an affected stakeholder will be and that any
attempt to codify a list of such stakeholders in the proposed standards could lead to errors due to the necessity of having to adopt a
one size fits all approach. No change made.
Western Area Power
Administration - Transmission
Owner

No

See answer to Question 1.

WAPA-RMR

No

See response to Question 1.

Platte River Power Authority

No

See answer to Question 1.

Response: See response to Q1.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

38

Organization

Yes or No

Massachusetts Attorney General

No

Question 3 Comment
Don't buy the 75 MW or the 25 MW thresholds.

Response: The SDT established the values based on the results of the Section 1600 data request. While the SDT considered other
values, the data collected did not justify such an action. No change made.
Entergy Services, Inc.
(Transmission)

No

Attachment 1 is overly burdensome and unnecessary.

Response: With no specifics provided, the SDT is unable to respond further. However, the SDT does not believe the process to be
overly burdensome or unnecessary. No change made.
SCE&G

No

Comments previously submitted.

Response: Thank you for following the guideline. Please see previous responses to this comment posted for the comment period
ending November 19, 2012.
Independent Electricity System
Operator

No

The process presented in Section III is overly prescriptive and requires information
not necessary to the intended purpose.
As stated in Q1, we disagree with prescribing a fixed MW threshold for NonConsequential Load Loss in a continent-wide standard, and propose alternate
language as stated in Q1 comments and supporting reasons. If this section must
deal with a review of the use of footnote ‘b’/’12’ to ensure that there are no
widespread adverse reliability impacts on the bulk power system, then it should be
limited to the information required for that purpose. Provided there is local
support for the use of Non-Consequential Load Loss under footnote ‘b’/’12’, only
information items 6 and 8 from section II are relevant for this assessment-the
remainder are not required for this section and should be deleted.
The use of footnote ‘b’/’12’ should not be limited to the Near-Term Planning
Horizon. We propose that the words “in Year One of the Planning Assesssment” be
deleted.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

39

Organization

Yes or No

Question 3 Comment
Items 1 and 2 complicate this section and are unnecessary. They should be
replaced by a phrase such as “for those planning events where the use of footnote
‘b’/’12’ is referenced”.
We disagree with the need to submit to the ERO for a determination of whether
there are any adverse reliability impacts caused by the use of Non-Consequential
Load Loss. This will introduce a new type of review at the ERO that will create
unnecessary delays and burden, and is inconsistent with and not required for all of
the other performance requirements in the TPL standards. Submitting the analysis
to the adjacent Planning Coordinators and Transmission Planners, and any
functional entity that requests it, as called for in requirement R8 of TPL001-2
should be sufficient.

Response: The SDT does not believe the section is overly prescriptive or duplicative as described below. No change made.
Please see response to Q1.
The use of the footnote is not limited to the Near-Term Transmission Planning Horizon since the main body of the footnote states
that the footnote may be utilized “… throughput the planning horizon…”. An entity has the freedom to make a business decision
concerning the use of footnote ‘b’ compared to other alternatives. An entity is free to determine when they want to assure that the
local regulator does not object but it must do so no later than Year One of the Planning Assessment. No change made.
The SDT believes that items 1 and 2 are needed to describe when an entity must assure that there are no regulatory objections. No
change made.
While the ERO may not need all of the information in Section II to perform its Adequate Reliability Impact evaluation, the SDT wanted
to minimize the burden on entities by allowing the submittal of an information package that already existed. The ERO is aware of the
proposed responsibility and has accepted this role if the industry approves. The SDT believes that it is the responsibility of the ERO to
assess Adverse Reliability Impacts and is not an appropriate role for adjacent planners. No change made.
Pacific gas and Electric Comapny

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We disagree with the inclusion of the information in Section II.2.a (the estimated
number and type of customers affected) and II.2.b (An assessment of the use of
Firm Demand interruption under footnote ‘b’ on the health, safety, and welfare of
the community). We suggest removing them. Section II.2.a is an administrative
40

Organization

Yes or No

Question 3 Comment
process and not needed for reliability of the Bulk Power System. Section II.2.b is
vague and can be interpreted numerous ways, which make compliance difficult. It
can also become a legal liability issue for the service provider, even if that loss of
load is judged to be a prudent decision by the “applicable regulatory authorities or
governing bodies responsible for retail electric service issues”.

Response: The SDT believes that the information shown in Section II is necessary to allow stakeholders to understand the usage of
footnote ‘b’. No change made.
SDG&E

No

Response: Without a specific comment, the SDT is unable to respond.
ISO New England Inc

The footnote states “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 does not object to the use of Non-Consequential Load Loss
under footnote 12 if either...”. Section 215 of the Federal Power Act clearly
delineates Federal, State and Local authority. State and Local requirements should
not be introduced into a NERC standard. In addition to the jurisdictional issues,
proving that the “applicable regulatory authority or governing body” does not
object is more difficult than proving that they simply approved the use of nonconsequential load loss. The SDT should remove all references to State and Local
authority from the standard.
Overall, the order of Section III is also notable. During year, two through ten of the
overall planning horizon the standard allows for Non-Consequential Load Loss
without approval. In the first year of the assessment, approval becomes required
for Non-Consequential Load Loss. At this point, it is too late to allow for any other
alternative.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

41

Organization

Yes or No

Question 3 Comment
The Regional Entities with NERC oversight perform periodic audits and require selfcertification of the planning process. By virtue of the audit and self-certification
process, NERC has the ability to monitor the use of Non-Consequential Load Loss in
planning assessments. State and Local approval of practices called for in ERO
Standards is inappropriate.
In addition to being notable for the year one timing, Section III seems incomplete.
In the case where there is objection to Non-Consequential Load Shedding, the
process appears to end without resolution.

Response: In Order 693, FERC clearly stated that it has jurisdiction over matters that involve BES operations and reliability.
Furthermore, these orders mandate the ERO to write standards and requirements to address all aspects of BES operations and
reliability in support of these goals. The proposed footnote ‘b’ solution acknowledges these facts and is an appropriate response to
subsequent FERC directives on this matter. The footnote does not place requirements on local regulators but rather provides them
an opportunity to participate in the stakeholder process. No change made.
An entity has the freedom to make a business decision concerning the use of footnote ‘b’ compared to other alternatives. An entity
is free to determine when they want to assure that the local regulator does not object but it must do so no later than Year One of the
Planning Assessment. No change made.
Without the details now contained in the proposed footnote, there is no guarantee that NERC would have the information to
monitor the use of Non-Consequential Load Loss. The footnote does not place requirements on local regulators but rather provides
them an opportunity to participate in the stakeholder process. No change made.
If there is an objection by the regulators, then an entity cannot utilize footnote ‘b’ as proposed as part of the Corrective Action Plan
for Year One. No change made.
Ameren

Yes

We find no substantive changes to section III, and still believe that no objection
from a regulatory body requires, at a minimum, a tacit approval.

Response: The SDT believes that there are a variety of practices employed by regulatory bodies. Therefore, it is determined by the
planning entity and the applicable regulatory bodies as to how to show ‘no objection’. No change made.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

42

Organization

Yes or No

SERC EC Planning Standards
Subcommittee

Yes

Question 3 Comment
Change "does" to "do" in the last sentence of the first paragraph and in the first
sentence of the last paragraph in Section III of Attachment 1.

Response: The SDT agrees and has made the suggested grammatical change.
Section III – “… the applicable regulatory authorities or governing bodies responsible for retail electric service issues does not
object …”
Northeast Power Coordinating
Council

Yes

Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light

Bonneville Power
Administration

Yes

ACES Standards Collaborators

Yes

Brazos
Duke Energy

Yes

TVA Transmission Reliability
Engineering and Controls

Yes

Southern Company

Yes

American Electric Power

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

43

Organization

Yes or No

Idaho Power Company

Yes

Tacoma Power

Yes

ITC

Yes

Georgia Transmission Corp.

Yes

Oncor Electric Delivery Company
LLC

Yes

Question 3 Comment

Response: Thank you for your support.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

44

4.

If you have any other comments on this Standard that you haven’t already mentioned above, and that are not simply
reiterating previous comments that the SDT has already responded to, please provide them here:

Summary Consideration: The SDT has responded to the individual comments and there are no changes proposed to the standards as a
result of comments. However, the SDT did uncover a typo that has been corrected as shown below.
TPL-002-1c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as Firm Demand t: (1) …”
Organization

Yes or No

Hydro-Quebec TransEnergie

No

Question 4 Comment
HQT still considers that the non application of footnote 12 to categories P2 (breaker
fault), P4 (stuck breaker) and P5 (failure of a non redundant relay) is not correct,
when the footnote is applied to other categories such as P3, P6 and P7 (loss of
double-circuit lines). The SDT has indicated that the applicability of footnote 12 to
categories P2, P4 and P5 is not included in Project 2012-11. However, looking at
related Project 2006-02 where footnote 12 was brought up to Table 1, the matter of
applicability was not discussed in detail and the SDT did not clearly explain why
Non-Consequential Load Loss was not allowed for contingencies less frequent than
those for which it is allowed (internal breaker faults or stuck breakers are less
probable than double-circuit line faults). Discussion on this matter should not be
dismissed.

Response: Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. The
Board of Trustees has also previously approved this proposed standard. Discussions on the applicability of footnote 12 in that
standard were held during Project 2006-02 and are not part of this proceeding. No change made.
Bonneville Power
Administration

No

Duke Energy

No

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

45

Organization

Yes or No

American Electric Power

No

SDG&E

No

Idaho Power Company

No

Platte River Power Authority

No

SCE&G

No

Oncor Electric Delivery
Company LLC

No

Pacific gas and Electric
Comapny

No

Question 4 Comment

Response: Without a specific comment, the SDT is unable to respond.
ACES Standards Collaborators

Yes

Brazos

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) In regard to the changes relating to Demand-Side Management, we agree with
the wording, “For purposes of this footnote, the following are not counted as Firm
Demand: (1) Demand directly served by the Elements removed from service as a
result of a Contingency, or (2) Interruptible Demand or Demand-Side Management
Load.” However, the most recent change has created some confusion by replacing
“or” with “and” that potentially and inadvertently may exclude the use of DSM in all
locations but on the facilities removed from service. This would render DSM
ineffective. Now, the both (1) and (2) must occur in order to not be counted as Firm
Demand. We recommend changing the wording back to “or” so each option (1) OR
(2) is independently excluded from Firm Demand for footnote b. Connecting the
options with the word “and” changes the meaning and requires entities to meet
both option (1) and option (2) to be excluded from Firm Demand. Demand directly
served by the Elements removed from service as a result of a Contingency should be

46

Organization

Yes or No

Question 4 Comment
excluded, as should Interruptible Demand or Demand-Side Management Load
regardless of its location. A registered entity does not need to have both for the
exclusion.
(2) Thank you for the opportunity to comment.

Response: The SDT does not agree that ‘and’ excludes the use of both items 1 and 2 since this is a list of options. However, while
researching your suggestion, the SDT discovered a typo in the language when the previous red-line was converted to a clean copy.
This has been corrected as shown.
TPL-001-2c: footnote ‘b’ – “…For purposes of this footnote, the following are not counted as Firm Demand t: (1) …”
Hydro One Networks Inc.

Yes

As previously stated in our response to Question #1, Hydro One would like to
reiterate our position presented during the initial comment period. We believe that
the SDTs response to our initial comments did not correctly address the issues
because it did not recognize the Reliability Standards framework that is effective in
the Province of Ontario and possibly other Canadian provinces.

Response: Please see the response to Q1.
MISO

Yes

ITC
JDRJC Associates LLC

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

As previously stated, it is the general intent of the existing TPL-002-1 standard and
proposed TPL-001-2 standard to not rely on any shedding of Non-Consequenital
Load to meet a single contingency event. Accordingly, MISO submits that footnote
b of TPL-002-1 and footnote 12 of TPL-001-2 should be struck. However, in the
event that the footnotes in question are not eliminated, the footnote should be
narrowly focused only on those situations for which the original footnote was
developed, i.e., the interruption of service to radial customers or some local area
Network customers connected to or supplied by the Faulted element or by the
affected area, where the overall reliability of the interconnected transmission
system is not impacted. MISO therefore proposes the following alternate language
for footnote b and footnote 12 to ensure it is not misapplied:”An objective of the
planning process is to avoid Non-Consequential Load Loss following Contingency

47

Organization

Yes or No

Question 4 Comment
events. In limited circumstances, Non-Consequential Load Loss may be needed
within the planning horizon to ensure that BES performance requirements are
satisfied. However, Non-consequential Load shed cannot be used to avoid
cascading outages or to maintain system stability. Non-consequential load shed
also cannot be used to avoid a thermal loading or voltage limit violation on an extra
high voltage (EHV) facility. When Non-Consequential Load Loss is utilized within the
transmission planning horizon to address BES performance requirements, such
interruption cannot exceed 75 MW and is limited to the following circumstances: o
Non-consequential Load shed is allowed for load served by a radial transmission line
to avoid voltage limit violations on the radial transmission line following a single
contingency event. o Non-consequential load shed is allowed for load within a local
area served by not more than two Transmission Circuits and/or Transformers to
avoid a thermal loading issue or voltage issue within the local area, including the
Transmission Circuits and/or Transformers directly supplying the local area, for a
loss of a single element within the local area, including one of the Transmission
Circuits or Transformers directly supplying the local area, so long as there are no
thermal loading or voltage violations outside the local area.” MISO believes the
language above would ensure the continuing reliability of the Bulk Electric System
by limiting load shed and violations that require load shed to radial areas or areas
that would be served radially following the single contingency.
In addition, MISO has significant concerns regarding use of a stakeholder process to
determine if non-conseqeuntial load shedding is appropriate following a single
contingency event, as expressed in MISO’s comments on previous drafts of this
Project. In particular, MISO has concerns regarding whether such a stakeholder
process could be sufficiently open and transparent given the many, competing
interests of the responsible entity and affected stakeholders. Without such
sufficient openness and transparency, it is likely that stakeholder processes will not
result in consistent determinations of the appropriateness of the application of
footnote b in NERC TPL-002-1 and/or footnote 12 in TPL-001-2. Stated differently,
MISO is concerned that such stakeholder processes will always be subject to the

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

48

Organization

Yes or No

Question 4 Comment
biases of the participating parties, with the sheer number of parties determining the
outcome of the process. As an example, should a particular process be dominated
by parties that may be responsible for payment of upgrades but that are not
impacted by the alternative load shed, those stakeholders impacted by the
alternative load loss would be relegated to a minority position, resulting in majorityimposed stakeholder decisions to shed load. On the other hand, if the stakeholder
process is limited to only the stakeholders directly impacted by the proposed load
shed, to the extent those stakeholders pay only a small part of the upgrade costs,
they will always choose to avoid load shed - even if such decision requires a
potentially costly upgrade. Consequently, MISO has concerns that the inclusion of a
requirement for a fair and impartial stakeholder process to determine if and when
load shed is acceptable to assist in satisfying a single contingency standard is not
realistically attainable.
MISO therefore recommends that Attachment I be eliminated and that the
footnotes either be eliminated or replaced with the modified version above.

Response: The SDT believes that the suggested language adopts a one-size fits all approach that is not conducive to a continent-wide
standard. The footnote allows for circumstances outside of the suggested language scenarios, as well as those described in the
suggestion, to be resolved utilizing an open and transparent process. No change made.
The SDT believes that the inclusion of stakeholders including regulators provides an appropriate method for addressing the issues
that the commenter has raised. No change made.
BC Hydro

Yes

BC Hydro appreciates the efforts of the SDT in revising standards TPL-002-1c System Performance Following Loss of a Single BES Element (footnote b) and TPL001-2a - Transmission System Planning Performance Requirements (footnote 12).
BC Hydro votes YES in support of this ballot and wishes to provide the following two
comments: 1.At this time BC Hydro has concerns about the level of stakeholder
consultation that might be required as a result of the implementation of this
standard and will bring this concern to the attention of our regulator if necessary.
2.At this time BC Hydro has concerns about the instances for which regulatory

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

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Question 4 Comment
review of non-consequential load loss under footnote 12 is required and will discuss
those with our regulator if necessary.

Response: The SDT appreciates your overall support. In addition, please see the changes shown in Q1 for non-US registered entities.
Central Lincoln

Yes

Flathead

Central Lincoln has not paid much attention to this standard, since it is not
applicable to this entity's registered functions. However, we are disturbed by the
direction the standard is taking. The slides from the recent webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf)
state that "The 75 MW cap will require construction of major Transmission
projects." This is in direct conflict with the definition of "reliability standard" as
provided in section 215 of the FPA where it states "...the term does not include any
requirement to enlarge such facilities or to construct new transmission capacity..."
The webinar slide does offer alternatives to construction, but we don't see those
providing any reliability benefit. Some of the suggestions apparently only relate to
contract language, which cannot possibly relate in any way to "reliable operation"
as defined in section 215. Central Lincoln is is concerned that the revised language
oversteps the bounds of the "reliability standard" definition under Section 215 of
the Federal power Act and into customer service issues that are better served by,
and under the jurisdiction of, state and local utility boards and commissions.

Response: The statement from the January 8, 2013 webinar is a concern that industry had raised during the course of the project,
which the SDT had captured on a slide in order to respond to the concern during the webinar. The SDT pointed out that building is
not the sole source of remedy for the situation and provided specific examples in the webinar
(http://www.nerc.com/docs/Standards/dt/footnoteb_webinar_20130108_final.pdf (slide 13)). In Order 693, FERC clearly stated that
it has jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
Electric Reliability Council of
Texas, Inc.

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

ERCOT believes that the revisions to the footnote b attachment are an
improvement from the previous version. However, ERCOT does not believe that the

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Question 4 Comment
SDT provided a technical rationale for disagreeing with the comments that we
previously submitted. We fundamentally disagree with the approach of defining a
stakeholder process in the attachment to a footnote in a reliability standard. While
footnotes and attachments have been used in other standards we believe that this
application is not appropriate.
ERCOT believes that the footnote should be removed altogether as it does not meet
the objectives of FERC Order 693. We also believe that FERC did not mandate that a
stakeholder process be used. As stated in the January 8 NERC Industry Webinar,
90% of planning entities have not used the existing footnote b over a planning
horizon of 13 years. To incorporate an attachment to a footnote with a complicated
and prescriptive stakeholder process to address a few instances seems to be a least
common denominator approach to planning which is opposed to FERC’s direction.
Consistent with the approach of TPL-001-2, ERCOT recommends raising the bar on
reliability and removing the footnote from the standard.

Response: The SDT used the Board of Trustees approved standard as a starting point for this draft. FERC remanded the standard; not
because it contained a stakeholder process, but because the process was not well defined, did not include quantitative and
qualitative criteria for allowing curtailment of Firm Demand and did not assure that BES reliability would be maintained. The balloted
draft added detail and specificity to the already approved approach. The use of footnotes and attachments is an acceptable
mechanism for use in Reliability Standards and both mechanisms have been used before. No change made.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Southern Company

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

Footnote b contains no technical basis for allowing load dropping. It is completely
based on an administrative procedure. This is not responsive to paragraphs 17 and
32 of the FERC remand order. A technical basis has to be proposed. The
"temporarily radial" concept that was proposed in earlier drafts will address this
problem. It will give a technical basis for when load dropping would be allowed. If a
technical basis is developed like FERC requires, then there is no need for a
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Question 4 Comment
stakeholder process. The stakeholder process is not a bright line criteria which can
be enforced; it will change depending on the make-up of stakeholders and
therefore create inconsistencies across the grid. This approach should never be
used in a reliability standard. NERC adopted the ANSI standard process as the bench
mark in developing its reliability standards. ANSI does not use stakeholder
processes. We propose that the stakeholder process be eliminated. Create a
technical basis for when load dropping can be utilized. Keep the 75 MW maximum
amount of load that can be dropped.

Response: The SDT believes that the proposed approach is responsive to the Remand Order since it contains quantitative criteria and
a more well-defined stakeholder process. The temporary radial concept was discussed by the SDT but abandoned due to industry
comments that pointed to the difficulties in adopting this concept on a continent-wide basis. The attachment is enforceable as a clear
set of expectations has been described. The conclusions reached as a result of following the stakeholder process may be different
due to local configurations, constraints, and expectations of applicable regulatory bodies. No change made.
WAPA-RMR

Yes

I believe that the 75 MW limit is abetrary and could be too low given particular
circumstances, like the maginitude of recent load growth in the area, regulatory
hurdles in building new transmission, etc.
I also believe that the Attachment 1 stakeholder process is not needed, since it is
already covered by the FERC Ordered 890 planning process.

Western Area Power
Administration - Transmission
Owner

Yes

Western believes that the 75 MW limit is arbitrary and could be to low given
particular circumstances, like the magnitude of recent load growth in the area,
regulatory hurdles in building new transmission, etc.
We also believe that the Attachment 1 stakeholder process is not needed, since it is
already covered by the FERC Order 890 process.

Response: The SDT established the limit based on the results of the Section 1600 data request which clearly pointed to a 75 MW
limit. While the SDT considered a higher limit value, the data collected does not justify such an action. The SDT used the Board of
Trustees approved standard as a starting point for this draft. FERC remanded the standard; not because it contained a stakeholder
Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

52

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Question 4 Comment

process, but because the process was not well defined, did not include quantitative and qualitative criteria for allowing curtailment
of Firm Demand and did not assure that BES reliability would be maintained. The balloted draft added detail and specificity to the
already approved approach. The use of footnotes and attachments is an acceptable mechanism for use in Reliability Standards and
both mechanisms have been used before. No change made.
The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to allow an
entity to use an existing process as long as it meets the requirements shown in Attachment 1. No change made.
Entergy Services, Inc.
(Transmission)

Yes

If Attachment 1 must remain, Entergy would support the SERC PSS suggestion to
limit the application of Attachment 1 (the stakeholder process) to only those
situations where the non-consequential load at risk is above 25MW.

Response: As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The
current proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to
be supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Manitoba Hydro

Yes

Manitoba Hydro cannot support the Footnote B attachment which imposes a
stakeholder process not required in Manitoba.

Response: The open and transparent stakeholder process is a new requirement for all entities in response to the need to clarify
footnote ‘b’. No change made.
seattle city light

Yes

SCL abstains from voting on the revisions to footnote "b" in TPL-002-1c and the
corresponding footnote 12 of TPL-001-2. SCL is concerned that the revised
language oversteps the bounds of the "reliability standard" definition under Section
215 of the Federal power Act and into customer service issues that are better
served by, and under the jurisdiction of, state and local utility boards and
commissions (for details on SCL's concerns please see the comments submitted
during the initial ballot). However, in the spirit of moving this process forward,
SCL will not vote against the revised footnotes.

Public Utility District No.1 of

Yes

The Public Utility District No.1 of Snohomish County will abstain from voting on the

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

53

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Question 4 Comment

Snohomish County

revisions to footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL001-2. The Public Utility District No.1 of Snohomish County is concerned that the
revised language oversteps the bounds of the "reliability standard" definition under
Section 215 of the Federal power Act and into customer service issues that are
better served by, and under the jurisdiction of, state and local utility boards and
commissions (for details on the Public Utility District No.1 of Snohomish County's
concerns please see the comments submitted during the initial ballot). However, in
the spirit of moving this process forward, the Public Utility District No.1 of
Snohomish County will not vote against the revised footnotes.

ISO New England Inc

In summary, this standard as proposed has misplaced jurisdictional authority under
Section 215 of the Federal Power Act. The removal of references to State and Local
authorities in the standard is required.

National Grid

Yes

We are accepting the standard as written because our current practices are better
then the prescribed maximum limit. However, we believe the appropriate limit
should be determined on a case by case basis with the state regulator input. This
standard as written, does give us the flexibility to do this.

Response: The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities.
And when such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview
of footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
New Brunswick System
Operator

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We do not agree with setting a MW limit for non-consequential load loss. The
allowable amount should be determined and approved by the jurisdiction of the
area(s) whose load is affected. The intent of the TPL standard and this footnote is to
ensure that if non-sequential load loss is accounted for or relied up to ensure BES
reliability (as assessed in the planning horizon), that such a decision needs to be

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Question 4 Comment
approved by the appropriate jurisdiction

Response: Please see the changes shown in Q1 to account for jurisdictional differences for non-US registered entities.
MRO NSRF

Yes

Some entities remain concerned over a potential conflict and mismatch of impacts
introduced by Section III and the inclusion of non-regulated stakeholders versus
NERC regulated entities. There was not a FERC directive to include section III.
Section III overreaches the intent of the FERC order and the SAR to meet the FERC
directive. The drafting team should show the specific FERC requirement and words
in Order 693 that requires non-NERC regulatory reviews. The drafting team
technically responded to a request that Section III be removed, but avoided the the
fundamental issue. The fact that some existing non-NERC regulatory bodies may
already have a consistent practice is not a reason to include non-NERC entities into
a NERC framework. This creates a fundamental mismatch between NERC regulated
entities that must follow NERC standards and stakeholders that are not compelled
by NERC requirements. If Section III is not deleted, it is recommended that wording
be added to allow the existing FERC Order 890 stakeholder meeting process be used
to meet Attachment 1. Regulators attend these meetings and all stakeholders
(including regulators) could be asked for their objections. If there was no response
or a “lack of dissent”, this would be documented as meeting Attachment 1 to allow
the use of footnote “b” without additional special procedures.

Response: The phrase in Section I: “The responsible entity can utilize an existing process or develop a new process” was designed to
allow an entity to use an existing process as long as it meets the criteria shown in Attachment 1. No change made.
Iberdrola USA

Yes

The reasons for the “negative” vote are enumerated in our prior comments. In
summary: 1. Attachment 1 is cumbersome and inappropriate, and should be
stricken entirely.
2. All non-consequential load loss for all single-element contingencies should be
temporary, with an action plan to avoid such load loss in the future.

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

55

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Question 4 Comment
3. All actions following single-element contingencies should be an attempt to
restore lost customer service, not interrupt more customers.

Response: The transparency provided by the stakeholder process will meet the regulatory guidance provided on this issue. The
limited use of footnote ‘b’ as shown by the data collected in response to the Section 1600 data request indicates relatively few
instances where footnote ‘b’ would be used. For this reason, the SDT believes that the proposed approach strikes the right balance. .
No change made.
The SDT agrees that this is often the normal course of action. However, the SDT has not mandated this course of action since there
could be circumstances that may arise where the continued use of footnote ‘b’ may be the best over-all solution for all concerned.
No change made.
The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to meet the
performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed environment
where such usages can be discussed and resolved in an open and transparent process. No change made.
Southwest Power Pool
Reliability Standards
Development Group

Yes

Kansas City Power & Light

Under section II items 3 and 4 the wording (frequency and duration) seems to
implicate that the planners will be determining these events in a probabilistic
manor. If the probability of these events is anything other than 0 planners will have
to accommodate for those events in their planning assessments regardless of how
small the probability is for that event.

Response: The SDT does not agree that the wording requires a probabilistic determination. The planning method utilized to make the
determination is left up to the planner however this information is necessary to allow stakeholders to understand the usage of
footnote ‘b’. No change made.
ITC

Yes

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

While ITC is voting yes for this “successive ballot”, we are doing so in the interest of
ensuring that TPL 001-2 becomes fully effective as soon as possible. TPL001-2 is a
major improvement to previous standards and insuring it becomes fully effective is
important to ITC and the industry. However, we have concerns that we would like
to be noted. Because footnote B has been highlighted and expanded, there is the
possibility of future “unintended consequences”. It is highly likely that interveners

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Question 4 Comment
or others may attempt to stop or slow down needed corrective action plans, that do
not rely on load shedding, by suggesting that planners use this stakeholder process
before proposing projects. We suggest both NERC and FERC be prepared to deal
with these unintended consequences. We also concur in entirety with the
comments MISO is proposing to make for this project. They are consistent with past
comments ITC has made and do discuss in some detail the potential “unintended
consequences” this detailed footnote may cause.

Response: The SDT believes that special circumstances may exist where such actions as described in footnote ‘b’ are appropriate to
meet the performance requirements of TPL. The footnote allows for such circumstances to exist in a controlled and prescribed
environment where such usages can be discussed and resolved in an open and transparent process. No change made.
Xcel Energy

Yes

While we are not satisfied with the responses to our previous comments, we have
chosen to not reiterate them here. Instead, we feel that the need to continue with
any modification to Footnote b seems moot considering FERC's recent approval of
the revised BES definition. Specifically, we believe exclusions E1 and E3, regarding
radial systems and local networks, resolves FERC's original directive on ambiguity
with footnote b. We recommend the team consider abandoning this project, and
request that NERC staff request relief from FERC on the related directives, as they
have been overcome by the modified BES definition.

Response: The SDT believes that there may be portions of the BES, even with the proposed revised BES definition, where it may still
be appropriate to address performance issues using footnote ‘b’ for Non-Consequential Load Loss. No change made.
Independent Electricity System
Operator

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

(1) The IESO reiterate its support for allowing load interruption for a single
contingency with sufficient review/oversight and under acceptable conditions,
including no widespread adverse impact on the reliability of the interconnected
bulk power system. The reliability aspects (BES performance requirements) should
be reviewed for acceptability by the adjacent Planning Coordinators and
Transmission Planners. However, issues pertaining to economics or externalities
which may not be directly reliability-related are always available for review and

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Question 4 Comment
debate by the stakeholders via the regulatory processes and subject to approval by
the regulatory authority of each jurisdiction (including those in Canada and Mexico).
(2) Furthermore, we request that Table 1 of TPL-001-3 (previous TPL-001-2
approved by NERC BOT) be corrected for EHV contingencies in P2, P4 and P5
categories to allow the application of footnote ‘b’/’12’ that is allowed for the P1
events. Events in P2, P4, and P5 can involve more elements and can be more
onerous and stressful to the system than the P1 events, and if use of footnote
‘b’/’12’ is permitted in the less stressful P1 events, it should also be permitted in P2,
P4 and P5 events. There continues to be confusion as to this inconsistency, and to
how this is to be applied (as discussed at the last webinar).
(3) We suggest that NERC Standards and their requirements should focus on what is
the anticipated outcome rather than how to achieve it. Accordingly, we believe that
the focus of footnote ‘b’, and footnote 12 should be that interruption of load must
not have a widespread, adverse impact on the reliability of the interconnected bulk
power system. A continent-wide standard should not concern itself with the
reliability of supply or supply continuity for local load, as that is the responsibility of
the applicable regulatory authority or its agencies responsible for local transmission
and retail service over the load to be curtailed. As mentioned above, NERC
Standards and their requirements should focus on what is the anticipated outcome
rather than how to achieve it. In this regard, we believe that Attachment 1 is not
necessary because it prescribes a process which goes beyond the outcome of the
standard and dictates how stakeholdering must be carried out. The individual
jurisdiction should establish the process for ensuring compliance with the standard
and decide to what extent a stakeholdering process is necessary to establish the
acceptable level of load rejection for the area in a manner consistent with local
transmission established service levels.
(4) The process presented in Section I is overly prescriptive. If a section that
prescribes the principles of a stakeholder process is required, then for Canadian
entities this section should simply state that any threshold should be established in

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

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Question 4 Comment
a manner consistent with other service levels that apply to local transmission and
retail service for the load to be curtailed, as described in Q1 and for the reasons
stated therein.
Corrective action plans can rarely be implemented in a one-year time frame, and in
some cases, limited use of Non-consequential Load Loss will be preferable to
unaffordable transmission enhancements, therefore we believe that the use of
footnote ‘b’/’12’ should not be limited to the Near-Term Transmission Planning
Horizon. We propose that the phrase “the Near-Term Transmission Planning
Horizon of” be deleted from the opening paragraph.

Response: The SDT believes that it is the responsibility of the ERO to assess Adverse Reliability Impacts and is not an appropriate role
for adjacent planners. The proposed stakeholder process allows all stakeholders, including regulators, will have the necessary
information required for the indicated reviews. No change made.
Table 1 in the proposed TPL-001-2 was previously approved by industry through the standards development process. As shown by
this approval, the SDT and the industry disagree that there is a technical irregularity in Table 1. The Board of Trustees has also
previously approved this proposed standard. Discussions on the applicability of footnote 12 in that standard were held during
Project 2006-02 and are not part of this proceeding. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. In addition, please see the changes shown in Q1 to address
jurisdictional concerns for non-US registered entities. No change made.
Please see the changes shown in Q1 to address jurisdictional concerns for non-US registered entities.
The use of the footnote is not limited to the Near-Term Transmission Planning Horizon since the main body of the footnote states
that the footnote may be utilized “… throughput the planning horizon…”. No change made.
SERC EC Planning Standards
Subcommittee

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

We continue to recommend that up to 25 MW of planned interruption be allowed
without triggering the need for a stakeholder process. We believe that this
simplification would be less burdensome and would enhance industry acceptance of
the revision, while still meeting regulatory guidance. The comments expressed
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Question 4 Comment
herein represent a consensus of the views of the above-named members of the
SERC EC Planning Standards Subcommittee only and should not be construed as the
position of SERC Reliability Corporation, its board, or its officers.

TVA Transmission Reliability
Engineering and Controls

We recommend that up to 25 MW of planned interruption be allowed without
triggering the need for a stakeholder process. We believe that this simplification
would be less burdensome and would enhance industry acceptance of the revision,
while still meeting regulatory guidance.

Response: As approved by the Board of Trustees, all utilizations of footnote ‘b’ required the use of the stakeholder process. The
current proposal does not, and should not, deviate from this premise. The Remand Order stated that quantitative criteria needed to
be supplied for the stakeholder process and the current proposal provides that criteria. No change made.
Tacoma Power

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

While Tacoma Power appreciates NERC's attempt to address both footnotes with
the same drafting team, Tacoma Power is voting negative on the revisions to
footnote "b" in TPL-002-1c and the corresponding footnote 12 of TPL-001-2.
However, Tacoma Power would vote affirmative if a re-circulation ballot was limited
strictly to footnote "b" in TPL-002-1c. TPL-001-2 considered new types of outages
not considered by TPL version 1, such as P2-1. Although TPL-001-2 was approved by
the industry, the proposed modifications to footnote 12 in TPL-001-2 are
significantly more onerous than footnote 12 in TPL-001-2. Furthermore, since TPL001-2 is not yet enforceable, some Transmission Planners still do not realize that
automatic relay actions are considered Non Consequential Load Loss. In addition,
Tacoma Power identified over 100 MW of load in multiple locations that would be
shed in accordance with footnote 12 in TPL-001-2. Unfortunately, the structure of
the Section 1600 data request did not allow for the submittal of footnote 12 related
data. Since it is clear that the potential impact of the footnote 12 revision has not
been addressed due to the compressed timeline, Tacoma Power believes that by
separating the two standards, NERC can meet the FERC mandated deadline for
footnote b while still continuing the drafting process to achieve true industry
consensus on footnote 12. Please note that FERC orders 693 and 762 require
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Question 4 Comment
addressing only footnote "b" by the using the Expedited Standards Development
Process. Earlier FERC orders discuss "single contingencies" as type Category B in
TPL-002-1; FERC has not addressed Non Consequential Load Shedding for the lower
probability "single contingencies" (i.e. P2-1) in TPL-001-2. Approving the revisions to
footnote 12 would result in negligible reliability gains at an unreasonable cost for
customers on the fringes of the power system, without affording local jurisdictional
cost benefit analysis.
Tacoma Power is also concerned that the revised language oversteps the bounds of
the "reliability standard" definition under Section 215 of the Federal Power Act.
These revisions tread on customer service issues that are better served by, and
under the jurisdiction of, state and local utility boards and commissions. For details
on Tacoma Power's concerns please see the comments submitted during the initial
ballot. However, in the spirit of moving this process forward, Tacoma Power would
vote to approve the revisions to solely TPL-002-1c if balloted separately from TPL001-2.Tacoma Power appreciates the opportunity to provide comments, and thanks
you for consideration of our comments.

Response: Any information gleaned from a Section 1600 data request based on application of footnote 12 would have been
speculative prior to the implementation of the new TPL-001-2. From the review of the comments submitted, it does not appear that
separation of the standards would be a consensus view. No change made.
The proposed solution allows for input and participation at every step of the process by local jurisdictional authorities. And when
such decisions do not involve any aspect of BES operation or reliability, such situations would not come under the purview of
footnote ‘b’ as standards only apply to the BES unless stated otherwise. However, in Order 693, FERC clearly stated that it has
jurisdiction over matters that do involve BES operations and reliability. Furthermore, these orders mandate the ERO to write
standards and requirements to address all aspects of BES operations and reliability in support of these goals. The proposed footnote
‘b’ solution acknowledges these facts and is an appropriate response to subsequent FERC directives on this matter. No change made.
END OF REPORT

Consideration of Comments: Project 2010-11
Posting Date: January 22, 2013

61

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1.
2.
3.
4.

SAR approved by SC in May 2012.
Initial comment period July 31, 2012 – August 29, 2012.
Initial ballot and comment period October 5, 2012 – November 19, 2012.
Successive ballot and comment period December 10, 2012 – January 11, 2013

Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions

Anticipated Date

1. Recirculation ballot

January 2013

2. BOT approval

February 2013

Draft 8: January 2013

1

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 8: January 2013

2

Standard TPL-001-3 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-3

4.1. Functional Entity

5.

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-001-3, 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-001-3:










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)

B. Requirements

Draft 8: January 2013

3

Standard TPL-001-3 — Transmission System Planning Performance 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 :
•
•
•
•
•
•

Draft 8: January 2013

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.
Controllable Loads and Demand Side Management.

4

Standard TPL-001-3 — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

Draft 8: January 2013

5

Standard TPL-001-3 — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

Draft 8: January 2013

6

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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
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.

Draft 8: January 2013

7

Standard TPL-001-3 — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 8: January 2013

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

8

Standard TPL-001-3 — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

Draft 8: January 2013

9

Standard TPL-001-3 — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft8: January 2013

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-3 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft8: January 2013

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-3 — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft8: January 2013

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-3 — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft8: January 2013

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-3 — 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, &
Draft8: January 2013

14

Standard TPL-001-3 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
67), and tripping (#86, & 94).

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15

Standard TPL-001-3 — 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
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Standard TPL-001-3 — 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.

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Standard TPL-001-3 — 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.

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Standard TPL-001-3 — 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
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Standard TPL-001-3 — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 8: January 2013

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.

20

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

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21

Standard TPL-001-3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

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22

Standard TPL-001-3 — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 8: January 2013

Action

Change Tracking

23

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

Standard Development Roadmap
This section is maintained by the drafting team during the development of the standard and will be
removed when the standard becomes effective.
Development Steps Completed:
1. SAR approved by SC in May 2012.
2. Initial comment period July 31, 2012 – August 29, 2012.
3. Initial ballot and comment period October 5, 2012 – November 19, 2012.
3.4. Successive ballot and comment period December 10, 2012 – January 11, 2013
Proposed Action Plan and Description of Current Draft:

The SDT is working to address FERC’s remand of the proposed clarification of TPL-002, Table
1 — footnote ‘b’, regarding the planned or controlled interruption of electric supply where a
single Contingency occurs on a Transmission System. That footnote is captured here as footnote
12.
Future Development Plan:
Anticipated Actions

Successive ballot

Anticipated Date
December 2012

1. Recirculation ballot

January 2013

2. BOT approval

February 2013

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1

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

Definitions of Terms Used in Standard
This section includes all newly defined or revised terms used in the proposed standard. Terms already
defined in the Reliability Standards Glossary of Terms are not repeated here. New or revised definitions
listed below become approved when the proposed standard is approved. When the standard becomes
effective, these defined terms will be removed from the individual standard and added to the Glossary.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission system performance and
Corrective Action Plans to remedy identified deficiencies.

Draft 8: December 2012January 2013

2

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

A. Introduction
1.

Title:

Transmission System Planning Performance Requirements

2.

Number:

3.

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.

4.

Applicability:

TPL-001-2a3

4.1. Functional Entity

5.

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-001-23, 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-001-2a3:










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)

B. Requirements

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3

Standard TPL-001-2a3 — Transmission System Planning Performance 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.
Controllable Loads and Demand Side Management.

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4

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

•
2.1.5.

2.2.

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:
•
•
•
•
•

2.5.

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.

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

Draft 8: December 2012January 2013

5

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

studies as qualified in Requirement R2, Part2.6 and shall include documentation to
support the technical rationale for determining material changes.
2.6.

2.7.

Past studies may be used to support the Planning Assessment if they meet the
following requirements:
2.6.1.

For steady state, short circuit, or Stability analysis: the study shall be five
calendar years old or less, unless a technical rationale can be provided to
demonstrate that the results of an older study are still valid.

2.6.2.

For steady state, short circuit, or Stability analysis: no material changes have
occurred to the System represented in the study. Documentation to support
the technical rationale for determining material changes shall be included.

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.

If situations arise that are beyond the control of the Transmission Planner or
Planning Coordinator that prevent the implementation of a Corrective Action
Plan in the required timeframe, then the Transmission Planner or Planning
Coordinator is permitted to utilize Non-Consequential Load Loss and
curtailment of Firm Transmission Service to correct the situation that would
normally not be permitted in Table 1, provided that the Transmission Planner
or Planning Coordinator documents that they are taking actions to resolve the
situation. The Transmission Planner or Planning Coordinator shall
document the situation causing the problem, alternatives evaluated, and the

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6

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

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
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.

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7

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

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.

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:
4.3.1.1.

4.3.1.2.

4.3.1.3.

Draft 8: December 2012January 2013

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

8

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

4.3.2.

4.4.

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.

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.

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.

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9

Standard TPL-001-2a3 — 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

Initial Condition

Normal System

P1
Single
Contingency

Normal System

Event

1

Fault Type

None

N/A

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

3Ø

5. Single Pole of a DC line
1.
2.

P2
Single
Contingency

7

N/A

Bus Section Fault

Non-Consequential
Load Loss Allowed

EHV, HV

No

No

EHV, HV

No

9

No

12

EHV, HV

No

9

No

12

EHV

No

9

HV

Yes

3

No

SLG

Normal System
8

4. Internal Breaker Fault (Bus-tie Breaker)

Draft78: October 2012January 2013

Interruption of Firm
Transmission
4
Service Allowed

BES Level

SLG

Opening of a line section w/o a fault

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

2

Yes

EHV

No

9

No

HV

Yes

Yes

EHV, HV

Yes

Yes

SLG
8

SLG

10

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements
Category

P3
Multiple
Contingency

Initial Condition

Loss of generator unit
followed by System
9
adjustments

Event

1

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

P4
Multiple
Contingency
(Fault plus stuck
10
breaker )

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)

P6
Multiple
Contingency
(Two
overlapping
singles)

Normal System

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

Draft78: October 2012January 2013

Delayed Fault Clearing due to the failure of a
13
non-redundant relay 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
6
3. Shunt Device
4. Single pole of a DC line

Fault Type

3Ø

2

BES Level

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

EHV, HV

No

9

EHV

No

9

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV

No

HV

Yes

Yes

EHV, HV

Yes

Yes

EHV, HV

Yes

Yes

No

12

SLG
No

SLG

SLG

9

No

SLG

3Ø

SLG

11

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements
Category

Initial Condition

P7
Multiple
Contingency
(Common
Structure)

Normal System

Draft78: October 2012January 2013

Event

1

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

Fault Type

SLG

2

BES Level

EHV, HV

3

Interruption of Firm
Transmission
4
Service Allowed

Non-Consequential
Load Loss Allowed

Yes

Yes

12

Standard TPL-001-2a3 — 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:
11
a. Loss of a tower line with three or more circuits.
11
b. Loss of all Transmission lines on a common Right-of-Way .
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.

Draft78: October 2012January 2013

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:
10
13
a. 3Ø fault on generator with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
b. 3Ø fault on Transmission circuit with stuck breaker or a relay
13
failure resulting in Delayed Fault Clearing.
10
13
c. 3Ø fault on transformer with stuck breaker or a relay failure
resulting in Delayed Fault Clearing.
10
13
d. 3Ø fault on bus section with stuck breaker or a relay failure
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

13

Standard TPL-001-2a3 — 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, &
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14

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements
Table 1 – Steady State & Stability Performance Footnotes
(Planning Events and Extreme Events)
67), and tripping (#86, & 94).

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15

Standard TPL-001-2a3 — 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
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Standard TPL-001-2a3 — 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 does 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
In no case can the planned Non-Consequential Load Loss under footnote 12 exceed 75 MW.
Once assurance has been received that the applicable regulatory authorities or governing bodies
responsible for retail electric service issues does 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.

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Standard TPL-001-2a3 — 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.

Draft78: October 2012January 2013

Standard TPL-001-2a3 — 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
Draft78: October 2012January 2013

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

2. Violation Severity Levels

R1

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.

R2

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.

R3

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.

Draft 78: July 2012January 2013

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.

20

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

OR

Table 1.

OR

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

OR

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.

R4

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.

R5

N/A

N/A

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.

R6

N/A

N/A

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.

Draft 78: July 2012January 2013

21

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

Lower VSL

Moderate VSL

High VSL

Severe VSL

R7

N/A

N/A

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.

R8

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,

OR,

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.

Draft 78: July 2012January 2013

22

Standard TPL-001-2a3 — Transmission System Planning Performance Requirements

E. Regional Variances
None.
Version History
Version

Date

1

03/17/2001

Revision of TPL-001-0 to modify only Table 1 footnote b.
Approved by Board of Trustees

Project 2006-02 –
revision to address FERC
directive

2

To be
Determined

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 TPL006-0.

Project 2006-02 –
complete revision

2a

February
2013

Address remand of proposed footnote ‘b’ pursuant to FERC
Order RM06-16-009

Revised

Draft 78: July 2012January 2013

Action

Change Tracking

23

Implementation Plan for TPL-001-3
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
TPL-001-3 — Transmission System Planning Performance Requirements
In revising the TPL standards, the SDT is assuming that planners will receive valid data from the MOD
standards link described in TPL-001-3, Requirement R1. Furthermore, there is a tacit assumption that
future revisions of the MOD standards will include steps to validate MOD based data.
Revision to Sections of Approved Standards and Definitions
There are multiple new definitions in the proposed standard.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission System performance and
Corrective Action Plans to remedy identified deficiencies.

Compliance with Standards
Standard
TPL-001-3 — Transmission
System Planning Performance
Requirements

Functions That Must Comply With the Associated Requirements
Transmission Planner
Planning Coordinator
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this standard.
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.

1

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-001-2, 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-001-3:










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)

TPL-001-1a, TPL-002-2b, TPL-003-1b, and TPL-004-1a are being retired as they are replaced in their
entirety by TPL-001-3. TPL-005-0 and TPL-006-0.1 are being retired because their requirements are
adequately covered by the revised TPL-001-3 and NERC’s Rules of Procedure, Section 800. TPL-0011a, TPL-002-2b, TPL-003-1b, TPL-004-1a, TPL-005-0 and TPL-006-0.1 are being retired on midnight

of the day immediately prior to the Effective Date of TPL-001-3 in the particular jurisdictions in
which TPL-001-3 is becoming effective. However, during this 24-month period, all aspects of TPL001-1a through TPL-006-0.1 shall remain in effect for compliance monitoring. This 24 month period is to
allow entities to develop, perform and/or validate new and/or modified studies, methodologies,
assessments, procedures, etc. necessary to implement and meet the TPL-001-2a requirements. The
specified effective dates are expected to allow sufficient time for proper assessment of the available
options necessary to create a viable Corrective Action Plan that is compliant with the new Standard.
R1. This Requirement is related to maintaining System models and the data needed to do so. This
requirement shall become effective on the first day of the first calendar quarter, 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
this requirement goes into effect on the first day of the first calendar quarter, 12 months after
Board of Trustees adoption.
R7. This Requirement identifies an obligation to determine individual and joint responsibilities
for performing studies needed to do the Planning Assessment. This requirement shall become
effective on the first day of the first calendar quarter, 12 months after applicable regulatory
approval. In those jurisdictions where no regulatory approval is required, this requirement goes

2

into effect on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption.
TPL-001-3 ‘raises the bar’ in several areas where performance requirements have been changed in the new
Standard versus those in existing TPL-001-1a, TPL-002-2b, TPL-003-1b and TPL-004-1a because loss of
Non-Consequential Load or interruption of firm transfers is no longer allowed for certain events, whereas the
existing Standards were interpreted by many to allow such actions. As shown in Table 1 of TPL-001-3, the
performance requirements associated with the following events represent “raising the bar”:









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)

This “raising the bar” is beyond the control of the Transmission Planner and Planning Coordinator and
may have significant budget, siting, permitting, and construction impacts on many Transmission Owners.
To provide stakeholders with sufficient time to implement changes, a timeframe coincident with the end
of the Near-Term Transmission Planning Horizon has been provided
Any entity which cannot eliminate the need to trip Non-Consequential Load or curtail Firm Transmission
Service for these performance elements by that date shall submit a mitigation plan to its Regional Entity
outlining the steps it will take to correct the problem. If the entities follow the established ERO procedure
for mitigation, it is the intent of the SDT that no penalties will be assessed.

3

Implementation Plan for TPL-001-2a3
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress or
approved, that must be implemented before this standard can be implemented.
TPL-001-2a 3 — Transmission System Planning Performance Requirements
In revising the TPL standards, the SDT is assuming that planners will receive valid data from the MOD
standards link described in TPL-001-2a3, Requirement R1. Furthermore, there is a tacit assumption that
future revisions of the MOD standards will include steps to validate MOD based data.
Revision to Sections of Approved Standards and Definitions
There are multiple new definitions in the proposed standard.
Bus-tie Breaker: A circuit breaker that is positioned to connect two individual substation bus
configurations.
Consequential Load Loss: All Load that is no longer served by the Transmission system as a result
of Transmission Facilities being removed from service by a Protection System operation designed to
isolate the fault.
Long-Term Transmission Planning Horizon: Transmission planning period that covers years six
through ten or beyond when required to accommodate any known longer lead time projects that may take
longer than ten years to complete.
Non-Consequential Load Loss: Non-Interruptible Load loss that does not include: (1)
Consequential Load Loss, (2) the response of voltage sensitive Load, or (3) Load that is disconnected
from the System by end-user equipment.
Planning Assessment: Documented evaluation of future Transmission System performance and
Corrective Action Plans to remedy identified deficiencies.

Compliance with Standards
Standard
TPL-001-2a 3 — Transmission
System Planning Performance
Requirements

Functions That Must Comply With the Associated Requirements
Transmission Planner
Planning Coordinator
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this standard.
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.

1

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-001-2, 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-001-2a3:










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)

TPL-001-1a, TPL-002-1c2b, TPL-003-1b, and TPL-004-1a are being retired as they are replaced in their
entirety by TPL-001-2a3. TPL-005-0 and TPL-006-0.1 are being retired because their requirements are
adequately covered by the revised TPL-001-2a 3 and NERC’s Rules of Procedure, Section 800. TPL001-1a, TPL-002-1c2b, TPL-003-1b, TPL-004-1a, TPL-005-0 and TPL-006-0.1 are being retired on

midnight of the day immediately prior to the Effective Date of TPL-001-2a3 in the particular
jurisdictions in which TPL-001-2a 3 is becoming effective. However, during this 24-month period,
all aspects of TPL-001-1a through TPL-006-0.1 shall remain in effect for compliance monitoring. This 24
month period is to allow entities to develop, perform and/or validate new and/or modified studies,
methodologies, assessments, procedures, etc. necessary to implement and meet the TPL-001-2a
requirements. The specified effective dates are expected to allow sufficient time for proper assessment of
the available options necessary to create a viable Corrective Action Plan that is compliant with the new
Standard.
R1. This Requirement is related to maintaining System models and the data needed to do so. This
requirement shall become effective on the first day of the first calendar quarter, 12 months after
applicable regulatory approval. In those jurisdictions where no regulatory approval is required,
this requirement goes into effect on the first day of the first calendar quarter, 12 months after
Board of Trustees adoption.
R7. This Requirement identifies an obligation to determine individual and joint responsibilities
for performing studies needed to do the Planning Assessment. This requirement shall become
effective on the first day of the first calendar quarter, 12 months after applicable regulatory

2

approval. In those jurisdictions where no regulatory approval is required, this requirement goes
into effect on the first day of the first calendar quarter, 12 months after Board of Trustees
adoption.
TPL-001-2a 3 ‘raises the bar’ in several areas where performance requirements have been changed in the
new Standard versus those in existing TPL-001-1a, TPL-002-1c2b, TPL-003-1b and TPL-004-1a because
loss of Non-Consequential Load or interruption of firm transfers is no longer allowed for certain events,
whereas the existing Standards were interpreted by many to allow such actions. As shown in Table 1 of
TPL-001-2a3, the performance requirements associated with the following events represent “raising the bar”:









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)

This “raising the bar” is beyond the control of the Transmission Planner and Planning Coordinator and
may have significant budget, siting, permitting, and construction impacts on many Transmission Owners.
To provide stakeholders with sufficient time to implement changes, a timeframe coincident with the end
of the Near-Term Transmission Planning Horizon has been provided
Any entity which cannot eliminate the need to trip Non-Consequential Load or curtail Firm Transmission
Service for these performance elements by that date shall submit a mitigation plan to its Regional Entity
outlining the steps it will take to correct the problem. If the entities follow the established ERO procedure
for mitigation, it is the intent of the SDT that no penalties will be assessed.

3

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-1: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-2b: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-1: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-1: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-1: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-1c2b: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-1: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-1: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-1: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-2b: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-1: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-1: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

Implementation Plan for Project 2010-11: TPL Table 1 Order
Prerequisite Approvals
There are no other Reliability Standards or Standard Authorization Requests (SARs), in progress
or approved, that must be implemented before this standard can be implemented.
Revision to Sections of Approved Standards and Definitions
There are no new definitions in the proposed standards.
Compliance with Standards
Standards
TPL-001-1: System
Performance Under Normal
(No Contingency) Conditions
(Category A)
TPL-002-1c2b: System
Performance Following Loss
of a Single Bulk Electric
System Element (Category B)
TPL-003-1: System
Performance Following Loss
of Two or More Bulk Electric
System Elements (Category
C)
TPL-004-1: System
Performance Following
Extreme Events Resulting in
the Loss of Two or More Bulk
Electric System Elements
(Category D)

Functions That Must Comply With the Associated
Requirements
Transmission Planner
Planning Authority
X
X

Effective Dates
The effective date is the date entities are expected to meet the performance identified in this
standard.
The application of revised Footnote ‘b’ in Table 1 will take effect on the first day of the first
calendar quarter, 60 months after approval by applicable regulatory authorities. In those
jurisdictions where regulatory approval is not required, the effective date will be the first day of
the first calendar quarter, 60 months after Board of Trustees adoption or as otherwise made
effective pursuant to the laws applicable to such ERO governmental authorities. All other
116-390 Village Boulevard
Princeton, New Jersey 08540-5721
609.452.8060 | www.nerc.com

requirements remain in effect per previous approvals. The existing Footnote ‘b’ remains in
effect until the revised Footnote ‘b’ becomes effective.
All other requirements remain in effect as per previous approvals.

2

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-2b, footnote ‘b’ and TPL-001-3, footnote 12
Recirculation Ballot is now open through 8 p.m. Thursday, January 31, 2013
Now Available
A recirculation ballot is now open for revisions to a single footnote that is incorporated into two
standards (TPL-002-2b– System Performance Following Loss of a Single BES Element for footnote ‘b’,
and TPL-001-3 – Transmission System Planning Performance Requirements for footnote 12) through 8
p.m. Eastern Thursday, January, 31, 2013.
IMPORTANT NOTICE (PLEASE READ): This recirculation ballot includes a substantive change to TPL002-2b (formerly referred to as TPL-002-1c), footnote b and TPL-001-3 (formerly referred to as TPL001-2a), footnote 12 to address applicability to registered entities in Canada and Mexico. The change
adds text to the footnotes and Attachment 1 that addresses jurisdictional differences – specifically,
that the 75 MW limit on planned, non-consequential load loss included in the footnotes and
Attachment would not apply to Canadian or Mexican registered entities. The inclusion of this
substantive change during a recirculation ballot was approved by the Standards Committee as a
deviation from the Standard Processes Manual to provide NERC with an opportunity to meet a
February 2013 deadline from the Federal Energy Regulatory Commission.
Please also note that NERC has identified that the drafting team was given incorrect guidance on the
proper numbering of the standards to account for the revision to be consistent with the NERC
Standards Numbering Convention. The standards versions have been updated to reflect the
appropriate numbering convention and are now identified as TPL-002-2b and TPL-001-3.
Instructions
In the recirculation ballot, votes are counted by exception. Only members of the ballot pool may cast
a ballot; all ballot pool members may change their previously cast votes. A ballot pool member who
failed to cast a ballot during the last ballot window may cast a ballot in the recirculation ballot
window. If a ballot pool member does not participate in the recirculation ballot, that member’s vote
cast in the previous ballot will be carried over as that member’s vote in the recirculation ballot.
Members of the ballot pool associated with this project may log in and submit their vote for the
footnote by clicking here.

Next Steps
Voting results will be posted and announced after the ballot window closes. If approved, the footnote
will be submitted to the Board of Trustees for adoption and then filed with the appropriate regulatory
authorities.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.
Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process, including the appeals process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

Standards Announcement
Project 2010-11– TPL Table 1 Order
TPL-002-2b, footnote ‘b’ and TPL-001-3, footnote 12
Recirculation Ballot Results
Now Available
A recirculation ballot for revisions to a single footnote that is incorporated into two standards (TPL002-2b– System Performance Following Loss of a Single BES Element for footnote ‘b’, and TPL-001-3 –
Transmission System Planning Performance Requirements for footnote 12) concluded at 8 p.m.
Eastern on Thursday, January, 31, 2013.
Voting statistics are listed below, and the Ballot Results page provides a link to the detailed results.

Approval
Quorum: 88.55%
Approval: 69.63%
Next Steps
The footnote will be presented to the Board of Trustees for adoption and then filed with the
appropriate regulatory authorities.
Background
FERC Order No. 762, issued April 19, 2012, remanded TPL-002-0b to NERC as vague, unenforceable and
not responsive to the previous Commission directives on this matter. The Standards Committee
directed the Standards Drafting Team (SDT) to revise footnote ‘b’ in accordance with the directives of
Orders No. 693 and 762. The SDT was also charged with revising the corresponding footnote 12 of TPL001-2 in order to prevent the remand of TPL-001-2.
In revising the footnotes, the SDT adopted a philosophy of minimal changes to the actual footnote
itself. This was done to minimize confusion as to what was changed, for ease of reading and following
the footnote, and for formatting within the actual standards documents. Instead, the SDT revised the
footnote by developing an attachment to the footnote containing changes in response to the
Commission orders. It should be noted that attachments to standards are an extension of the
Requirements and thus are binding to applicable entities.

Project 2010-11 is an important part of the ERO’s strategic goal to be responsive to regulatory
authority directives in an expeditious manner in order to reduce the amount of standards-related
directives and to provide an adequate level of reliability.
Additional information can be found on the project page.
Standards Development Process
The Standards Processes Manual contains all the procedures governing the standards development
process, including the appeals process. The success of the NERC standards development process
depends on stakeholder participation. We extend our thanks to all those who participate.
For more information or assistance, please contact Monica Benson,
Standards Development Administrator, at [email protected] or at 404-446-2560.
North American Electric Reliability Corporation
3353 Peachtree Rd, NE

Suite 600, North Tower
Atlanta, GA 30326
404-446-2560 | www.nerc.com

Standards Announcement: Project 2010-11

2

NERC Standards

 

Newsroom  •  Site Map  •  Contact NERC

  
Advanced Search

 
User Name

Ballot Results

Ballot Name: Project 2010 -11 Recirculation Ballot Jan 2013_in

Password

Ballot Period: 1/22/2013 - 1/31/2013
Ballot Type: Recirculation

Log in

Total # Votes: 317

Register
 

Total Ballot Pool: 358
Quorum: 88.55 %  The Quorum has been reached

-Ballot Pools
-Current Ballots
-Ballot Results
-Registered Ballot Body
-Proxy Voters

Weighted Segment
69.63 %
Vote:
Ballot Results: The Standard has Passed

 Home Page
Summary of Ballot Results

Affirmative
Segment
 
1 - Segment 1.
2 - Segment 2.
3 - Segment 3.
4 - Segment 4.
5 - Segment 5.
6 - Segment 6.
7 - Segment 7.
8 - Segment 8.
9 - Segment 9.
10 - Segment 10.
Totals

Ballot Segment
Pool
Weight
 

 
102
10
82
25
73
48
0
8
3
7
358

#
Votes

 
1
0.9
1
1
1
1
0
0.5
0.2
0.6
7.2

#
Votes

Fraction
 

57
6
42
11
30
23
0
2
0
5
176

Negative

No
# Votes Vote

Fraction

 
0.814
0.6
0.724
0.786
0.732
0.657
0
0.2
0
0.5
5.013

Abstain

 
13
3
16
3
11
12
0
3
2
1
64

 
0.186
0.3
0.276
0.214
0.268
0.343
0
0.3
0.2
0.1
2.187

 
21
0
15
8
20
11
0
0
1
1
77

11
1
9
3
12
2
0
3
0
0
41

Individual Ballot Pool Results

Segment
 
1
1
1
1
1
1
1
1

Organization

 
 
Ameren Services
American Electric Power
American Transmission Company, LLC
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Austin Energy
Avista Corp.

Member
 
Vijay Sankar
Kirit Shah
Paul B. Johnson
Andrew Z Pusztai
Robert Smith
John Bussman
James Armke
Scott J Kinney

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

Ballot

Comments
 

Abstain
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Abstain

 

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

Balancing Authority of Northern California
Baltimore Gas & Electric Company
BC Hydro and Power Authority
Beaches Energy Services
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
CenterPoint Energy Houston Electric, LLC
Central Maine Power Company
City of Tacoma, Department of Public
Utilities, Light Division, dba Tacoma Power
City of Tallahassee
Clark Public Utilities
Colorado Springs Utilities
Consolidated Edison Co. of New York
Corporate Risk Solutions, Inc.
CPS Energy
Dairyland Power Coop.
Dayton Power & Light Co.
Deseret Power
Dominion Virginia Power
Duke Energy Carolina
Entergy Transmission
FirstEnergy Corp.
Florida Keys Electric Cooperative Assoc.
Florida Power & Light Co.
FortisBC
Gainesville Regional Utilities
Georgia Transmission Corporation
Great River Energy
Hoosier Energy Rural Electric Cooperative,
Inc.
Hydro One Networks, Inc.
Hydro-Quebec TransEnergie
Idaho Power Company
International Transmission Company Holdings
Corp
JEA
KAMO Electric Cooperative
Keys Energy Services
Lakeland Electric
Lee County Electric Cooperative
Lincoln Electric System
Long Island Power Authority
Lower Colorado River Authority
M & A Electric Power Cooperative
Manitoba Hydro
MEAG Power
MidAmerican Energy Co.
Minnkota Power Coop. Inc.
N.W. Electric Power Cooperative, Inc.
National Grid USA
Nebraska Public Power District
New Brunswick Power Transmission
Corporation
New York Power Authority
Northeast Missouri Electric Power Cooperative
Northeast Utilities
Northern Indiana Public Service Co.
NorthWestern Energy
Ohio Valley Electric Corp.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Oncor Electric Delivery
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
Portland General Electric Co.
Potomac Electric Power Co.

Kevin Smith
Christopher J Scanlon
Patricia Robertson
Joseph S Stonecipher
Donald S. Watkins
Tony Kroskey
John Brockhan
Joseph Turano Jr.
Chang G Choi
Daniel S Langston
Jack Stamper
Paul Morland
Christopher L de Graffenried
Joseph Doetzl
Richard Castrejana
Robert W. Roddy
Hertzel Shamash
James Tucker
Michael S Crowley
Douglas E. Hils
Oliver A Burke
William J Smith
Dennis Minton
Mike O'Neil
Curtis Klashinsky
Richard Bachmeier
Jason Snodgrass
Gordon Pietsch

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Negative
Affirmative

Affirmative
Affirmative

Bob Solomon
Ajay Garg
Bernard Pelletier
Molly Devine

Affirmative
Affirmative
Affirmative

Michael Moltane

Affirmative

Ted Hobson
Walter Kenyon
Stanley T Rzad
Larry E Watt
John W Delucca
Doug Bantam
Robert Ganley
Martyn Turner
William Price
Nazra S Gladu
Danny Dees
Terry Harbour
Daniel L Inman
Mark Ramsey
Michael Jones
Cole C Brodine

Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Affirmative
Affirmative
Affirmative

Randy MacDonald

Affirmative

Bruce Metruck
Kevin White
David Boguslawski
Kevin M Largura
John Canavan
Robert Mattey
Marvin E VanBebber
Doug Peterchuck
Jen Fiegel
Bangalore Vijayraghavan
Ryan Millard
John C. Collins
John T Walker
David Thorne

Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

NERC Standards
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1
1

PowerSouth Energy Cooperative
PPL Electric Utilities Corp.
Public Service Company of New Mexico
Public Service Electric and Gas Co.
Public Utility District No. 1 of Okanogan
County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Rochester Gas and Electric Corp.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Sho-Me Power Electric Cooperative
Sierra Pacific Power Co.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
South Mississippi Electric Power Association
Southern California Edison Company
Southern Company Services, Inc.
Southern Illinois Power Coop.
Southwest Transmission Cooperative, Inc.
Sunflower Electric Power Corporation
Tampa Electric Co.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
Tucson Electric Power Co.
United Illuminating Co.
Westar Energy
Western Area Power Administration
Xcel Energy, Inc.

2

BC Hydro

2
2
2
2
2
2
2
2
2
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3

California ISO
Electric Reliability Council of Texas, Inc.
Independent Electricity System Operator
ISO New England, Inc.
Midwest ISO, Inc.
New Brunswick System Operator
New York Independent System Operator
PJM Interconnection, L.L.C.
Southwest Power Pool, Inc.
AEP
Alabama Power Company
Ameren Services
APS
Associated Electric Cooperative, Inc.
Atlantic City Electric Company
Avista Corp.
BC Hydro and Power Authority
Bonneville Power Administration
Central Electric Power Cooperative
City of Austin dba Austin Energy
City of Bartow, Florida
City of Green Cove Springs
City of Homestead
City of Redding
City of Tallahassee
Colorado Springs Utilities
ComEd
Consolidated Edison Co. of New York
Consumers Energy
CPS Energy
Delmarva Power & Light Co.
Detroit Edison Company
Dominion Resources, Inc.
Duke Energy Carolina

Larry D Avery
Brenda L Truhe
Laurie Williams
Kenneth D. Brown

Affirmative
Affirmative
Affirmative
Affirmative

Dale Dunckel

Abstain

Rod Noteboom

Abstain

Denise M Lietz
John C. Allen
Tim Kelley
Robert Kondziolka
Terry L Blackwell
Pawel Krupa
Denise Stevens
Rich Salgo
Long T Duong
Tom Hanzlik
Rodney A. Wilson
Steven Mavis
Robert A. Schaffeld
William Hutchison
John Shaver
Noman Lee Williams
Beth Young
Howell D Scott
Tracy Sliman
John Tolo
Jonathan Appelbaum
Allen Klassen
Brandy A Dunn
Gregory L Pieper
Venkataramakrishnan
Vinnakota
Rich Vine
Cheryl Moseley
Barbara Constantinescu
Kathleen Goodman
Marie Knox
Alden Briggs
Gregory Campoli
stephanie monzon
Charles H. Yeung
Michael E Deloach
Robert S Moore
Mark Peters
Steven Norris
Chris W Bolick
NICOLE BUCKMAN
Robert Lafferty
Pat G. Harrington
Rebecca Berdahl
Adam M Weber
Andrew Gallo
Matt Culverhouse
Gregg R Griffin
Orestes J Garcia
Bill Hughes
Bill R Fowler
Charles Morgan
John Bee
Peter T Yost
Richard Blumenstock
Jose Escamilla
Michael R. Mayer
Kent Kujala
Connie B Lowe
Henry Ernst-Jr

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Affirmative
Abstain
Abstain
Abstain
Negative
Affirmative
Negative
Affirmative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative
Negative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Abstain

NERC Standards
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
3
4
4
4
4
4
4
4
4

Entergy
FirstEnergy Energy Delivery
Florida Municipal Power Agency
Florida Power Corporation
Georgia Power Company
Georgia System Operations Corporation
Great River Energy
Gulf Power Company
Hydro One Networks, Inc.
JEA
KAMO Electric Cooperative
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Louisville Gas and Electric Co.
M & A Electric Power Cooperative
Manitoba Hydro
MidAmerican Energy Co.
Mississippi Power
Modesto Irrigation District
Municipal Electric Authority of Georgia
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
Niagara Mohawk (National Grid Company)
Northeast Missouri Electric Power Cooperative
Northern Indiana Public Service Co.
NW Electric Power Cooperative, Inc.
Oklahoma Gas and Electric Co.
Orange and Rockland Utilities, Inc.
Orlando Utilities Commission
Owensboro Municipal Utilities
Pacific Gas and Electric Company
PacifiCorp
Platte River Power Authority
PNM Resources
Portland General Electric Co.
Potomac Electric Power Co.
Public Service Electric and Gas Co.
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Carolina Electric & Gas Co.
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Tri-County Electric Cooperative, Inc.
Tri-State G & T Association, Inc.
Westar Energy
Wisconsin Electric Power Marketing
Xcel Energy, Inc.
American Municipal Power
Arkansas Electric Cooperative Corporation
Blue Ridge Power Agency
City of Austin dba Austin Energy
City of New Smyrna Beach Utilities
Commission
City of Redding
City Utilities of Springfield, Missouri
Constellation Energy Control & Dispatch,
L.L.C.

Joel T Plessinger
Stephan Kern
Joe McKinney
Lee Schuster
Danny Lindsey
Scott McGough
Brian Glover
Paul C Caldwell
David Kiguel
Garry Baker
Theodore J Hilmes
Charles Locke
Gregory D Woessner
Mace D Hunter
Jason Fortik
Daniel D Kurowski
Charles A. Freibert
Stephen D Pogue
Greg C. Parent
Thomas C. Mielnik
Jeff Franklin
Jack W Savage
Steven M. Jackson
John S Bos
Tony Eddleman
David R Rivera
Michael Schiavone
Skyler Wiegmann
William SeDoris
David McDowell
Gary Clear
David Burke
Ballard K Mutters
Thomas T Lyons
John H Hagen
Dan Zollner
Terry L Baker
Michael Mertz
Thomas G Ward
Mark Yerger
Jeffrey Mueller
Erin Apperson
James Leigh-Kendall
John T. Underhill
James M Poston
Dana Wheelock
James R Frauen
Mark Oens
Hubert C Young
Travis Metcalfe
Ronald L. Donahey
Ian S Grant
Mike Swearingen
Janelle Marriott
Bo Jones
James R Keller
Michael Ibold
Kevin Koloini
Ronnie Frizzell
Duane S Dahlquist
Reza Ebrahimian
Tim Beyrle

Negative
Affirmative
Affirmative
Affirmative
Negative
Affirmative
Affirmative
Negative
Affirmative

Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Negative
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Negative
Negative
Affirmative
Negative
Affirmative
Negative
Affirmative
Abstain
Negative

Affirmative
Affirmative

Nicholas Zettel
John Allen

Abstain
Abstain

Margaret Powell

Affirmative

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

NERC Standards
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
4
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5

Consumers Energy
Detroit Edison Company
Flathead Electric Cooperative
Florida Municipal Power Agency
Fort Pierce Utilities Authority
Georgia System Operations Corporation
Integrys Energy Group, Inc.
Modesto Irrigation District
Ohio Edison Company
Public Utility District No. 1 of Douglas County
Public Utility District No. 1 of Snohomish
County
Sacramento Municipal Utility District
Seattle City Light
Seminole Electric Cooperative, Inc.
South Mississippi Electric Power Association
Tacoma Public Utilities
Wisconsin Energy Corp.
AEP Service Corp.
Amerenue
Arizona Public Service Co.
Associated Electric Cooperative, Inc.
Avista Corp.
BC Hydro and Power Authority
Boise-Kuna Irrigation District/dba Lucky peak
power plant project
Bonneville Power Administration
Brazos Electric Power Cooperative, Inc.
BrightSource Energy, Inc.
City and County of San Francisco
City of Austin dba Austin Energy
City of Redding
City of Tallahassee
City Water, Light & Power of Springfield
Cleco Power
Colorado Springs Utilities
Consolidated Edison Co. of New York
Consumers Energy Company
Dairyland Power Coop.
Detroit Edison Company
Detroit Renewable Power
Dominion Resources, Inc.
Duke Energy
Electric Power Supply Association
Energy Services, Inc.
Exelon Nuclear
FirstEnergy Solutions
Florida Municipal Power Agency
Great River Energy
JEA
Kansas City Power & Light Co.
Kissimmee Utility Authority
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
Massachusetts Municipal Wholesale Electric
Company
MEAG Power
MidAmerican Energy Co.
Muscatine Power & Water
Nebraska Public Power District
New York Power Authority
NextEra Energy
Northern Indiana Public Service Co.
Oklahoma Gas and Electric Co.
Omaha Public Power District
Orlando Utilities Commission

David Frank Ronk
Daniel Herring
Russ Schneider
Frank Gaffney
Cairo Vanegas
Guy Andrews
Christopher Plante
Spencer Tacke
Douglas Hohlbaugh
Henry E. LuBean
John D Martinsen
Mike Ramirez
Hao Li
Steven R Wallace
Steven McElhaney
Keith Morisette
Anthony Jankowski
Brock Ondayko
Sam Dwyer
Scott Takinen
Matthew Pacobit
Edward F. Groce
Clement Ma

Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Negative
Affirmative
Negative
Abstain
Affirmative
Abstain
Negative

Affirmative

Mike D Kukla
Francis J. Halpin
Shari Heino
Chifong Thomas
Daniel Mason
Jeanie Doty
Paul A. Cummings
Karen Webb
Steve Rose
Stephanie Huffman
Jennifer Eckels
Wilket (Jack) Ng
David C Greyerbiehl
Tommy Drea
Christy Wicke
Marcus Ellis
Mike Garton
Dale Q Goodwine
John R Cashin
Tracey Stubbs
Mark F Draper
Kenneth Dresner
David Schumann
Preston L Walsh
John J Babik
Brett Holland
Mike Blough
James M Howard
Dennis Florom
Kenneth Silver
S N Fernando
David Gordon
Steven Grego
Neil D Hammer
Mike Avesing
Don Schmit
Wayne Sipperly
Allen D Schriver
William O. Thompson
Kim Morphis
Mahmood Z. Safi
Richard K Kinas

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

Affirmative
Negative

Affirmative
Abstain
Affirmative

Abstain
Negative
Abstain
Affirmative
Abstain
Abstain
Affirmative

Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Abstain
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Affirmative

NERC Standards
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
5
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6
6

Platte River Power Authority
Portland General Electric Co.
PPL Generation LLC
PSEG Fossil LLC
Public Utility District No. 1 of Lewis County
Public Utility District No. 2 of Grant County,
Washington
Puget Sound Energy, Inc.
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
Southern California Edison Company
Southern Company Generation
Tacoma Power
Tampa Electric Co.
Tenaska, Inc.
Tennessee Valley Authority
Tri-State G & T Association, Inc.
U.S. Army Corps of Engineers
U.S. Bureau of Reclamation
Westar Energy
Wisconsin Electric Power Co.
Xcel Energy, Inc.
AEP Marketing
Ameren Energy Marketing Co.
APS
Associated Electric Cooperative, Inc.
Bonneville Power Administration
City of Austin dba Austin Energy
City of Redding
Cleco Power LLC
Consolidated Edison Co. of New York
Constellation Energy Commodities Group
Dominion Resources, Inc.
Duke Energy
Entergy Services, Inc.
FirstEnergy Solutions
Florida Municipal Power Agency
Florida Municipal Power Pool
Florida Power & Light Co.
Imperial Irrigation District
Kansas City Power & Light Co.
Lakeland Electric
Lincoln Electric System
Los Angeles Department of Water & Power
Manitoba Hydro
MidAmerican Energy Co.
Modesto Irrigation District
Muscatine Power & Water
New York Power Authority
Northern Indiana Public Service Co.
Omaha Public Power District
PacifiCorp
Platte River Power Authority
PPL EnergyPlus LLC
PSEG Energy Resources & Trade LLC
Sacramento Municipal Utility District
Salt River Project
Santee Cooper
Seattle City Light
Seminole Electric Cooperative, Inc.
Snohomish County PUD No. 1
South Mississippi Electric Power Association
Southern California Edison Company

Roland Thiel
Matt E. Jastram
Annette M Bannon
Tim Kucey
Steven Grega
Michiko Sell
Lynda Kupfer
Bethany Hunter
William Alkema
Lewis P Pierce
Michael J. Haynes
Brenda K. Atkins
Sam Nietfeld
Denise Yaffe
William D Shultz
Chris Mattson
RJames Rocha
Scott M. Helyer
David Thompson
Mark Stein
Melissa Kurtz
Martin Bauer
Bryan Taggart
Linda Horn
Liam Noailles
Edward P. Cox
Jennifer Richardson
Randy A. Young
Brian Ackermann
Brenda S. Anderson
Lisa L Martin
Marvin Briggs
Robert Hirchak
Nickesha P Carrol
David J Carlson
Louis S. Slade
Greg Cecil
Terri F Benoit
Kevin Querry
Richard L. Montgomery
Thomas Washburn
Silvia P. Mitchell
Cathy Bretz
Jessica L Klinghoffer
Paul Shipps
Eric Ruskamp
Brad Packer
Daniel Prowse
Dennis Kimm
James McFall
John Stolley
Saul Rojas
Joseph O'Brien
David Ried
Kelly Cumiskey
Carol Ballantine
Elizabeth Davis
Peter Dolan
Diane Enderby
Steven J Hulet
Michael Brown
Dennis Sismaet
Trudy S. Novak
Kenn Backholm
Joel Rogers
Lujuanna Medina

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

Negative
Affirmative
Affirmative
Affirmative
Abstain
Abstain
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Negative
Negative
Negative
Affirmative
Abstain
Negative
Negative
Affirmative
Abstain
Affirmative
Abstain
Negative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Affirmative
Abstain
Negative
Affirmative
Abstain
Affirmative
Negative
Affirmative
Affirmative
Affirmative
Affirmative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
Negative
Abstain
Negative
Affirmative
Abstain
Affirmative
Affirmative
Abstain
Negative
Affirmative
Affirmative
Abstain
Affirmative
Abstain
Abstain
Negative
Abstain
Negative

NERC Standards
6
6
6
6
6
6
6
8
8
8
8
8
8
8
8
9
9
9
10
10
10
10
10
10
10
 

Southern Company Generation and Energy
Marketing
Tacoma Public Utilities
Tampa Electric Co.
Tennessee Valley Authority
Westar Energy
Western Area Power Administration - UGP
Marketing
Xcel Energy, Inc.
 
 
JDRJC Associates
Massachusetts Attorney General
Transmission Strategies, LLC
Utility Services, Inc.
Utility System Effeciencies, Inc. (USE)
Volkmann Consulting, Inc.
Commonwealth of Massachusetts Department
of Public Utilities
National Association of Regulatory Utility
Commissioners
New York State Department of Public Service
Midwest Reliability Organization
New York State Reliability Council
Northeast Power Coordinating Council
ReliabilityFirst Corporation
SERC Reliability Corporation
Texas Reliability Entity, Inc.
Western Electricity Coordinating Council

John J. Ciza

Negative

Michael C Hill
Benjamin F Smith II
Marjorie S. Parsons
Grant L Wilkerson

Negative
Affirmative
Negative
Affirmative

Peter H Kinney

Affirmative

David F Lemmons
Edward C Stein
Roger C Zaklukiewicz
Jim Cyrulewski
Frederick R Plett
Bernie M Pasternack
Brian Evans-Mongeon
Robert L Dintelman
Terry Volkmann

Negative

Negative
Negative
Affirmative
Affirmative
Negative

Donald Nelson

Abstain

Diane J. Barney

Negative

Thomas G. Dvorsky
William S Smith
Alan Adamson
Guy V. Zito
Anthony E Jablonski
Carter B. Edge
Donald G Jones
Steven L. Rueckert
 

Legal and Privacy
 404.446.2560 voice  :  404.446.2595 fax  
Atlanta Office: 3353 Peachtree Road, N.E. : Suite 600, North Tower : Atlanta, GA  30326
Washington Office: 1325 G Street, N.W. : Suite 600 : Washington, DC 20005-3801

Copyright © 2012 by the North American Electric Reliability Corporation.  :  All rights reserved.
A New Jersey Nonprofit Corporation

https://standards.nerc.net/BallotResults.aspx?BallotGUID=f015f86b-7d80-430a-8d7c-db3f6d3a046d[2/1/2013 8:44:36 AM]

Negative
Affirmative
Negative
Abstain
Affirmative
Affirmative
Affirmative
Affirmative
 

 

 

Exhibit J
Standard Drafting Team Roster for NERC Standards Development Project 2011-10

Project 2010-11 TPL Table 1
Company and Address

Contact Info

Bio

John Odom, Chair
Vice President of
Planning and
Operations

Name and Title

Florida Reliability
Coordinating Council, Inc.
1408 N. Westshore Blvd.,
Suite 1002
Tampa, FL 33607-4512

(813)207-7985
jodom@
frcc.com

Douglas Hohlbaugh,
Vice Chair
Standards
Development Manager

FirstEnergy Corp.
76 South Main Street
10th Floor
Akron, Ohio 44308

(330) 384-4698
hohlbaughdg@
firstenergycorp.
com

D. Darrin Church
Principal Engineer
Bulk Transmission
Planning

Tennessee Valley Authority
1101 Market Street
MR 5G-C
Chattanooga, Tennessee
37402-2801

423) 751-6899
(423) 751-3453
Fx
ddchurch@tva.
gov

John Odom is Vice President of Planning and
Operations at the Florida Reliability Coordinating
Council (FRCC). John joined FRCC in May, 2005
after 26 years at Progress Energy Corporation (PEF).
He is responsible for oversight of all Member
Services Activities, including the FRCC standing
committees, FRCC Reliability Coordinator, and
Planning Authority function. Additionally, he
oversees the Regional Entity functions of reliability
assessment, situational awareness, training,
certification of system operators, and event analysis.
From 2001 – 2007, John was the FRCC
Representative on the NERC Reliability Assessment
Subcommittee (RAS). John is currently the chair of
the Assess Future Transmission Needs Standards
Drafting Team (AFTNSDT), which is re-writing the
existing TPL-001 through TPL-006.
Doug Hohlbaugh holds a Bachelor of Science in
Electrical Engineering from Akron University (1989)
and a Professional Engineering license in the state of
Ohio. His 20 plus years experience in the electric
utility industry has involved the transmission business
of FirstEnergy with a focus on transmission planning.
His work experience includes various technical
positions in transmission and distribution, as well as
sales and marketing experience with FirstEnergy’s
(FE) unregulated energy services
Existing responsibilities include the Reliability
Standards Development Lead of the FirstEnergy
FERC Compliance Department including oversight of
newly proposed and/or revised reliability standards
governing the bulk electric transmission system. The
responsibilities include overseeing and ensuring
timely implementation of all new reliability standard
development projects at both the North American
Electric Reliability Corporation (NERC) and
Reliability First Corporation (RFC) having impact on
a variety of FE business units which support the
reliable operation of the bulk transmission system.
Darrin Church is a Principal Bulk Planning Engineer
in TVA’s Transmission Planning Department. Darrin
has 15 years experience in Bulk Transmission
Planning along with 5 years previous experience in
planning relaying and protection schemes.
Responsibilities include insuring reliability of TVA’s
500 kV, 230 kV, 161 kV, and 115 kV transmission
systems which include initiating capital projects
required to maintain an adequate and reliable
transmission system per NERC Reliability Standards.

William Harm
Senior Consultant

PJM Interconnection, L.L.C.
955 Jefferson Ave
Valley Forge Corporate
Center
Norristown, Pennsylvania
19403-2497

(610) 666-8868
[email protected]

Julius Horvath
Manager
Planning & Operations

Wind Energy Transmission
Texas, LLC

(512)496-9186
julius.horvath@
windenergyofte
xas.com

Robert A. Jones
Project Manager,
Stability Studies

Southern Company Services
P.O. Box 2641
Birmingham, Alabama 35291

(205) 257-6148
rajones@
southernco.com

Brian K. Keel
Manager,
Transmission System
Planning

Salt River Project
MS POB100
PO Box 52025
Phoenix, Arizona 85072

602-236-0970
brian.keel@
srpnet.com

R. W. Mazur
Manager
System Planning
Department

Manitoba Hydro
12-1146 Waverly Street
P.O. Box 815
Winnipeg, Manitoba R3C
2P4

(204) 474-3113
rwmazur@
hydro.mb.ca

Thomas C. Mielnik
Manager
Electric System
Planning

MidAmerican Energy Co.
106 East Second Street
Davenport, Iowa 52808

(563) 333-8129
tcmielnik@
midamerican.co
m

Bill Harm has over 35 years of industry experience
with PJM through various assignments involving real
time operation, operations planning, and transmission
planning. Mr. Harm’s current responsibilities involve
performance assessment and policy development
responsibilities. He either has or continues to
represent PJM in various industry forums and groups,
including RFC, NERC, and the ISO/RTO forums. He
earned a Bachelor and Maters of Science Degree in
Electrical Engineering from Drexel University and is
a registered professional Engineer in the
Commonwealth of PA.
Julius Horvath is currently the Planning and
Operations Manager at Wind Energy Transmission
Texas, LLC (WETT), in Austin, Texas. Julius has
over 12 years of utility experience at the Bonneville
Power Administration, Wind Energy Transmission
Texas, LLC, Lonestar Transmission, LLC and the
Lower Colorado River Authority in Transmission
Planning. Julius is a Registered Profession Engineer
in the State of Texas.
Robert Jones obtained a BSEE degree from the
University of Alabama in 1973 and a MSEE degree
from University of Alabama – Birmingham in 1978.
He has worked for 37 years for Southern Company
Services. Eighteen of those years have been in
Transmission Planning. The last 15 years, he has been
responsible for stability studies for Southern
Company.
Brian Keel has a Bachelor and Master Degrees in
Electrical Engineering, specializing in power systems,
from the University of Illinois. Brian was employed
by Duke Power for over one year and PSI Energy for
8 years. Brian has been at SRP since 1998 and is
currently the Manager of Transmission System
Planning. Brian has Chaired four groups within
WECC mainly concentrating on transmission
reliability. Brian is a current member of the NERC
TADS Work Group.
Ronald W. Mazur obtained his Bachelor of Science in
Electrical Engineering degree in 1971, and his
Masters of Science in Electrical Engineering degree in
1989, both from the University of Manitoba. Ron
Mazur is a registered professional engineer with the
Association of Professional Engineers and
Geoscientists of Manitoba. Ron joined Manitoba
Hydro in 1974, where he worked in station design for
5 years, and in system performance (operations) for 6
years, and in system planning since 1986. He is
currently the Manager of the System Planning
Department responsible for the expansion planning of
Manitoba Hydro’s transmission system (100 kV and
above) and the HVDC system.
Ron is a Canadian representative on the NERC
Planning Committee, and Chair of the Planning
Committee of the Midwest Reliability Organization.
Thomas Mielnik has over 37 years experience in
Electric Utility Planning. He has been the
Manager of Electric System Planning for MEC
from 1995 to the present. He was a member of
the NERC ATC Working Group from 1996 to
1999 and is a Registered Professional Engineer.

Bernie M Pasternack,
President, P.E.

Transmission Strategies
4347 Harborough Rd
Upper Arlington, Ohio 43220

(614) 459-5806
bmpasternack@
att.net

Bob Pierce
Senior Engineer

Duke Energy
526 South Church Street
MC EC10Q
Charlotte, North Carolina
28201-1006

(980) 373-6480
bob.pierce@
dukeenergy.com

Bernie Pasternack was employed by the AEP Service
Corporation for over 41 years, where he spent his
entire career in various aspects of transmission
planning and asset management. After retiring from
AEP in June 2010, he formed his own consulting
practice, providing services to the electric utility
industry. He holds BEE and MSEE degrees from
Rensselaer Polytechnic Institute and an MBA from
Fairleigh Dickinson University.
Before retiring from AEP, Bernie was responsible for
the planning and management of AEP’s transmission
assets. His department provided the analytical and
planning services for the entire AEP System, eleven
operating companies, and a transmission network
consisting of transmission facilities ranging in voltage
from 23 kV to 765 kV. This system spans eleven
states and three reliabilty regions (RFC, SPP, and
ERCOT). Bernie was also responsible for providing
input to policy making decisions relative to AEP's
transmission strategy and business plan.
Bernie directed the analytical and planning services
provided to the eleven operating companies. Such
services included future system performance appraisal
and planning studies, IPP interconnection studies, and
all analytical studies dealing with the steady-state and
dynamic operation of interconnected power systems.
Based on an evaluation of the results of these studies,
the Transmission Planning group developed and
recommended capital improvement projects and
programs for the reinforcement of the AEP System
transmission network. In parallel with these efforts,
the Transmission Asset Engineering group developed
capital rehabilitation programs and set maintenance
guidelines to maintain the health of AEP’s
transmission assests.
During his career, Bernie has made significant
contributions to a variety of industry organizations
including IEEE, CIGRE, EPRI, EEI, ECAR/RFC, and
NERC. He was a member of the EEI Transmission
Policy TF and AEP's representative on the Reliability
First Corporation Reliability Committee. Bernie has
also played an active role in many NERC activities
over the past twenty years, including its Planning
Committee and a number of its subcommittees,
working groups, and standards drafting teams.
Robert (Bob) Pierce is a Consulting Engineer at Duke
Energy where he specializes in Bulk System Planning,
NERC standards, and FERC regulations. He holds a
B.S. in Nuclear Engineering from Pennsylvania State
University and a M.S. in Electrical Engineering from
the University of North Carolina-Charlotte. Mr. Pierce
is a registered Professional Engineer with 13 years
Transmission Planning experience and a total of 31
years of power system experience.

Dana Walters
Director of Reliability
and Economic
Planning

NYISO
10 Krey Blvd.,
Rensselaer, NY 12144

518-356-8582
DWalters@NYI
SO.com

Dana Walters is currently Director of Reliability and
Economic Planning at the NYISO. However, at the
time of the work effort he was a Manager in the
Transmission Planning group at National Grid. Mr.
Walters has 36 year of experience in the Electric
Utility industry. Most of his experience involves
various aspects of Transmission Planning. This
includes topics such as analytical studies of thermal,
stability, short circuit, generator interconnections, and
lightning protection. Other areas of experience include
involvement in investment planning, tariff design,
consulting, production cost analysis, and distribution
planning. In his role as a Transmission Planner, Mr.
Walters has been involved in numerous committees
and working groups at the NERC, NPCC, and ISO
levels. Mr. Walters has a Masters in Engineering
Management from Northeastern University and a
Bachelor in Electrical Engineering with a focus in
Power Systems also from Northeastern University.
Mr. Walters is a registered professional engineer in
New Hampshire and is a member of IEEE.


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