NERC Petition (without exhibits) in RM15-16

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability
Corporation

)
)

Docket No. ____________

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED TRANSMISSION OPERATIONS AND
INTERCONNECTION RELIABILITY OPERATIONS AND COORDINATION
RELIABILITY STANDARDS
Gerald W. Cauley
President and Chief Executive Officer
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
(404) 446-2595 – facsimile

Charles A. Berardesco
Senior Vice President and General Counsel
Holly A. Hawkins
Associate General Counsel
Shamai Elstein
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
(202) 644-8099 – facsimile
charles.berardesco@nerc.net
holly.hawkins@nerc.net
shamai.elstein@nerc.net
Counsel for the North American Electric
Reliability Corporation

March 18, 2015

TABLE OF CONTENTS

EXECUTIVE SUMMARY .................................................................................................... 4
NOTICES AND COMMUNICATIONS ................................................................................ 6
BACKGROUND .................................................................................................................... 6
A.

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

B.

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

C.

FERC Proceeding History ................................................................................................ 8

D.

Project 2014-03 – Revisions to TOP and IRO Standards ................................................ 9
JUSTIFICATION FOR APPROVAL................................................................................... 10

A.

Purpose of and Improvements in the Proposed Reliability Standards ........................... 11
1.

Purpose ....................................................................................................................... 11

2.

Improvements ............................................................................................................. 12

B.

Proposed Reliability Standards and Definitions............................................................. 17
1.

Proposed Definitions .................................................................................................. 17

2.

Proposed Reliability Standards ................................................................................... 21

C.

Consideration of the Southwest Outage Report Recommendations .............................. 35
1.

Operations Planning ................................................................................................... 38

2.

Near-and-long term planning...................................................................................... 44

3.

Situational Awareness ................................................................................................ 44

4.

Consideration of Bulk Electric System Equipment .................................................... 47

5.

Interconnection Reliability Operating Limit Derivations ........................................... 49

6.

Protection Systems ..................................................................................................... 49

7.

Angular Separation ..................................................................................................... 50

D.

E.

Consideration of TOP/IRO NOPR Concerns ................................................................. 50
1.

TOP Reliability Standards – Issues to be Addressed ................................................. 51

2.

TOP Reliability Standards – Issues Requiring Clarification ...................................... 53

3.

IRO Reliability Standards – Issues to be Addressed .................................................. 60

4.

IRO Reliability Standards – Issues Requiring Clarification ....................................... 61
Consideration of Outstanding Commission Directives .................................................. 61

F. Enforceability of Proposed Reliability Standards .............................................................. 68
CONCLUSION ..................................................................................................................... 69

i

TABLE OF CONTENTS

Exhibit A

Proposed Reliability Standards and Definitions

Exhibit B

Implementation Plan for Proposed Reliability Standards and Definitions

Exhibit C

Order No. 672 Criteria

Exhibit D

Mapping Document

Exhibit E

White Paper on System Operating Limit Definition and Exceedance Clarification

Exhibit F

Mapping Document of Proposed Reliability Standards to Southwest Outage
Report Recommendations

Exhibit G

Summary of NOPR Issues

Exhibit H

Consideration of Issues and Directives

Exhibit I

Consideration of NERC Operating Committee Response to NERC Standards
Committee RISC Triage of IERP Gaps

Exhibit J

Analysis of Violation Risk Factors and Violation Severity Levels

Exhibit K

Summary of Development History and Complete Record of Development

Exhibit L

Standard Drafting Team Roster for NERC Standards Development Project 201403

ii

UNITED STATES OF AMERICA
BEFORE THE
FEDERAL ENERGY REGULATORY COMMISSION

North American Electric Reliability
Corporation

)
)

Docket No. ____________

PETITION OF THE
NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION
FOR APPROVAL OF PROPOSED TRANSMISSION OPERATIONS AND
INTERCONNECTION RELIABILITY OPERATIONS AND COORDINATION
RELIABILITY STANDARDS
Pursuant to Section 215(d)(1) of the Federal Power Act 1 and Section 39.5 2 of the
regulations of the Federal Energy Regulatory Commission (“FERC” or “Commission”), the North
American Electric Reliability Corporation (“NERC”) 3 hereby submits for Commission approval
the following nine proposed Reliability Standards (Exhibit A): 4
•
•
•
•
•
•
•
•
•

TOP-001-3 (Transmission Operations);
TOP-002-4 (Operations Planning);
TOP-003-3 (Operational Reliability Data);
IRO-001-4 (Reliability Coordination – Responsibilities);
IRO-002-4 (Reliability Coordination –Monitoring and Analysis);
IRO-008-2 (Reliability Coordinator Operational Analyses and Real-time Assessments);
IRO-010-2 (Reliability Coordinator Data Specification and Collection);
IRO-014-3 (Coordination Among Reliability Coordinators); and
IRO-017-1 (Outage Coordination).

1

16 U.S.C. § 824o (2012).

2

18 C.F.R. § 39.5 (2014).

3

The Commission certified NERC as the electric reliability organization (“ERO”) in accordance with
Section 215 of the Federal Power Act (“FPA”) on July 20, 2006. N. Am. Elec. Reliability Corp., 116 FERC ¶
61,062 (2006) (“ERO Certification Order”).

4

Unless otherwise designated, all capitalized terms shall have the meaning set forth in the Glossary of Terms
Used in NERC Reliability Standards (“NERC Glossary”), available at
http://www.nerc.com/files/Glossary_of_Terms.pdf.

1

NERC requests that the Commission approve the proposed Reliability Standards and find
that each is just, reasonable, not unduly discriminatory or preferential, and in the public interest.
As discussed further below, the proposed Reliability Standards replace the Reliability Standards
currently pending with the Commission in Docket Nos. RM12-12-000, RM13-14-000 and RM1315-000 (the “Pending TOP/IRO Standards). 5
NERC also requests approval of: (i) revised definitions for the NERC Glossary terms
“Operational Planning Analysis” and “Real-time Assessment” (Exhibit A); (ii) the Implementation
Plan for the proposed Reliability Standards and definitions (Exhibit B); and (iii) the associated
Violation Risk Factors (“VRFs”) and Violation Severity Levels (“VSLs”) (Exhibits A and J).
Finally, NERC requests retirement of the following Reliability Standards.
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•
•

IRO-001-1.1 (Reliability Coordination – Responsibilities and Authorities);
IRO-002-2 (Reliability Coordination — Facilities)
IRO-003-2 (Reliability Coordination – Wide-Area View);
IRO-004-2 (Reliability Coordination – Operations Planning);
IRO-005-3.1a (Reliability Coordination – Current Day Operations);
IRO-008-1 (Reliability Coordinator Operational Analyses and Real-time
Assessments);
IRO-010-1a (Reliability Coordinator Data Specification and Collection);
IRO-014-1 (Coordination Among Reliability Coordinators);
IRO-015-1 (Notifications and Information Exchange Between Reliability
Coordinators);
IRO-016-1 (Coordination of Real-time Activities Between Reliability Coordinators);
PER-001-0.2 (Operating Personnel Responsibility and Authority);
TOP-001-1a (Reliability Responsibilities and Authorities);
TOP-002-2.1b (Normal Operations Planning);
TOP-003-1 (Planned Outage Coordination);
TOP-004-2 (Transmission Operations);
TOP-005-2a (Operational Reliability Information);

5

Concurrent with this filing, NERC is submitting a motion to withdraw the Reliability Standards pending
Commission approval in those dockets. Notice of Withdrawal of the North American Electric Reliability
Corporation, Docket Nos. RM13-12-000, RM13-14-000, and RM13-15-000 (Mar. 18, 2015).

2

•
•
•

TOP-006-2 (Monitoring System Conditions);
TOP-007-0 (Reporting System Operating Limit and Interconnection Reliability
Operating Limit Violations); and
TOP-008-1 (Response to Transmission Limit Violations).

As required by Section 39.5(a) of the Commission’s regulations, 6 this Petition presents the
technical basis and purpose of the proposed Reliability Standards and definitions, a summary of
the development history (Exhibit K), and a demonstration that the proposed Reliability Standards
meet the criteria identified by the Commission in Order No. 672 7 (Exhibit C).
This Petition is organized as follows: Section I of the Petition presents an executive
summary of the proposed Reliability Standards. Section II of the Petition provides the individuals
to whom notices and communications related to the filing should be provided. Section III provides
background on the regulatory structure governing the Reliability Standards approval process, as
well as information on the development of the proposed Reliability Standards. Section IV of the
Petition then discusses the proposed Reliability Standards and definitions in detail, including the
purpose and improvements of the proposed Reliability Standards and definitions. Section IV also
explains how the proposed Reliability Standards address:
•

6

the recommendations in the joint FERC and NERC report on the 2011 Arizona-Southern
California outages (“Southwest Outage Report”) (see also Exhibit F), 8

18 C.F.R. § 39.5(a) (2014).

7

The Commission specified in Order No. 672 certain general factors it would consider when assessing
whether a particular Reliability Standard is just and reasonable. See Rules Concerning Certification of the Electric
Reliability Organization; and Procedures for the Establishment, Approval, and Enforcement of Electric Reliability
Standards, Order No. 672, FERC Stats. & Regs. ¶ 31,204, at P 262, 321-37, order on reh’g, Order No. 672-A,
FERC Stats. & Regs. ¶ 31,212 (2006).
8

FERC and NERC, Arizona-Southern California Outage on September 8, 2011, Causes and
Recommendations (Apr. 27, 2012), available at http://www.ferc.gov/legal/staff-reports/04-27-2012-ferc-nercreport.pdf.

3

•

concerns raised by the Commission in the November 21, 2013 Notice of Proposed
Rulemaking, which proposed to remand the Pending TOP/IRO Standards (the “TOP/IRO
NOPR”) (see also Exhibit G), 9 and

•

outstanding FERC directives related to the proposed Reliability Standards (see also
Exhibit H).
EXECUTIVE SUMMARY
The proposed Transmission Operations (“TOP”) and Interconnection Reliability

Operations and Coordination (“IRO”) Reliability Standards address matters that are fundamental
to grid reliability as they pertain to the coordinated efforts to plan and operate the Bulk Electric
System in a reliable manner under both normal and abnormal conditions. As discussed further
below, the proposed Reliability Standards consolidate many of the currently effective TOP and
IRO Reliability Standards and replace the Pending TOP/IRO Standards in addressing the roles
and responsibilities of Reliability Coordinators, Transmission Operators and Balancing
Authorities with respect to planning and operating the Bulk Electric System. The proposed
Reliability Standards provide a comprehensive framework for reliable operations, with important
improvements to ensure the Bulk Electric System is operated within pre-established limits while
enhancing situational awareness and strengthening operations planning.
The proposed Reliability Standards establish or revise requirements for operations
planning, system monitoring, real-time actions, coordination between applicable entities, and
operational reliability data. Among other things, the proposed Reliability Standards help to
ensure that Reliability Coordinators and Transmission Operators work together, and with other
functional entities, to operate the Bulk Electric System within System Operating Limits
(“SOLs”) and Interconnection Reliability Operating Limits (“IROLs”). SOLs and IROLs are

9
Monitoring System Conditions- Transmission Operations Reliability Standard Transmission Operations
Reliability Standards Interconnection Reliability Operations and Coordination Reliability Standards, 145 FERC ¶
61,158 (2013) (“TOP/IRO NOPR”).

4

vital concepts in NERC’s Reliability Standards as they establish acceptable performance criteria
both pre- and post-contingency to maintain reliable Bulk Electric System operations.
The proposed TOP Reliability Standards generally address real-time operations and
planning for next-day operations, and apply primarily to the responsibilities and authorities of
Transmission Operators, although certain requirements apply to the roles and responsibilities of
the Balancing Authority. The proposed IRO Reliability Standards set forth the responsibility and
authority of Reliability Coordinators to provide for reliable operations. Reliability Coordinators
have an essential role in ensuring reliable operations, as they are the functional entities with the
highest level of authority and have the wide-area view of the Bulk Electric System.
The proposed Reliability Standards improve upon the currently effective TOP and IRO
Reliability Standards by eliminating gaps, ambiguities, and redundancies, and by improving the
overall quality of the TOP and IRO Reliability Standards. Specifically, the proposed Reliability
Standards include improvements over the currently effective TOP and IRO Reliability Standards
in key areas such as: (1) operating within SOLs and IROLs; (2) outage coordination; (3) situational
awareness; (4) improved clarity and content in foundational definitions; and (5) requirements for
operational reliability data.
For the reasons discussed herein, NERC respectfully requests that the Commission approve
the proposed Reliability Standards, the proposed revised definitions, and the proposed retirements.

5

NOTICES AND COMMUNICATIONS
Notices and communications with respect to this filing may be addressed to the
following: 10
Holly A. Hawkins*
Associate General Counsel
Shamai Elstein*
Senior Counsel
North American Electric Reliability
Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
holly.hawkins@nerc.net
shamai.elstein@nerc.net

Valerie L. Agnew*
Senior Director of Standards
North American Electric Reliability
Corporation
3353 Peachtree Road, N.E.
Suite 600, North Tower
Atlanta, GA 30326
(404) 446-2560
valerie.agnew@nerc.net

BACKGROUND
A.

Regulatory Framework

By enacting the Energy Policy Act of 2005, 11 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(b)(1)12
of the FPA states that all users, owners, and operators of the Bulk-Power System in the United
States will be subject to Commission-approved Reliability Standards. Section 215(d)(5) 13 of the
FPA authorizes the Commission to order the ERO to submit a new or modified Reliability
Standard. Section 39.5(a) 14 of the Commission’s regulations requires the ERO to file with the
10

Persons to be included on the Commission’s service list are identified by an asterisk. NERC respectfully
requests a waiver of Rule 203 of the Commission’s regulations, 18 C.F.R. § 385.203 (2014), to allow the inclusion
of more than two persons on the service list in this proceeding.

11

16 U.S.C. § 824o (2012).

12

Id. § 824(b)(1).

13

Id. § 824o(d)(5).

14

18 C.F.R. § 39.5(a).

6

Commission for its approval each Reliability Standard that the ERO proposes should become
mandatory and enforceable in the United States, and each modification to a Reliability Standard
that the ERO proposes should 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. Pursuant to
Section 215(d)(2) of the FPA 15 and Section 39.5(c) 16 of the Commission’s regulations, the
Commission will give due weight to the technical expertise of the ERO with respect to the content
of a Reliability Standard.
B.

NERC Reliability Standards Development Procedure

The proposed Reliability Standards and definitions were developed in an open and fair
manner and in accordance with the Commission-approved Reliability Standard development
process. 17 NERC develops Reliability Standards in accordance with Section 300 (Reliability
Standards Development) of its Rules of Procedure and the NERC Standard Processes Manual. 18
In its order certifying NERC as the Commission’s Electric Reliability Organization, the
Commission found that NERC’s proposed rules provide for reasonable notice and opportunity for
public comment, due process, openness, and a balance of interests in developing Reliability

15

16 U.S.C. § 824o(d)(2).

16

18 C.F.R. § 39.5(c)(1).

17

Rules Concerning Certification of the Electric Reliability Organization; and Procedures for the
Establishment, Approval, and Enforcement of Electric Reliability Standards, Order No. 672 at P 334, FERC Stats. &
Regs. ¶ 31,204, order on reh’g, Order No. 672-A, FERC Stats. & Regs. ¶ 31,212 (2006).

18

The NERC Rules of Procedure are available at http://www.nerc.com/AboutNERC/Pages/Rules-ofProcedure.aspx. The NERC Standard Processes Manual is available at
http://www.nerc.com/comm/SC/Documents/Appendix_3A_StandardsProcessesManual.pdf.

7

Standards 19 and thus satisfies certain of the criteria for approving Reliability Standards. 20 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 stakeholders must
approve, and the NERC Board of Trustees must adopt, a Reliability Standard before NERC
submits a proposed Reliability Standard to the Commission for approval.
C.

FERC Proceeding History

As noted above, the proposed Reliability Standards are intended to replace the Pending
TOP/IRO Standards, which consist of the following:
•

Reliability Standard TOP-006-3 (Monitoring System Conditions), which NERC filed on
April 5, 2013 in Docket No. RM13-12-000. The proposed revisions to Reliability Standard
TOP-006-3 were intended to divide the reporting responsibilities of Balancing Authorities
and Transmission Operators into separate requirements.

•

Reliability Standards TOP-001-2 (Transmission Operations), TOP-002-3 (Operations
Planning), TOP-003-2 (Operational Reliability Data) and PRC-001-2 (System Protection
Coordination), which NERC filed on April 16, 2013, in Docket No. RM13-14-000. These
Reliability Standards were intended to replace the eight currently effective TOP Reliability
Standards. 21

•

Reliability Standards: IRO-001-3 (Responsibilities and Authorities), IRO-002-3 (Analysis
Tools), IRO-005-4 (Current Day Operations), and IRO-014-2 (Coordination Among
Reliability Coordinators), which NERC filed on April 16, 2013, in Docket No. RM13-15000. These four Reliability Standards were intended to replace six currently effective IRO
Reliability Standards (IRO‐001‐1.1, IRO-002-2, IRO-005-3a, IRO-014-1, IRO-015-1, and
IRO-016-1).
On November 21, 2013, the Commission issued the TOP/IRO NOPR, proposing to approve

proposed Reliability Standard TOP-006-3 but remand the other Pending TOP/IRO Standards. A

19

ERO Certification Order at P 250.

20

Order No. 672 at PP 268, 270.

21

The changes in proposed Reliability Standard PRC-001-2 were administrative in nature and limited to
removal of three requirements in currently effective Reliability Standard PRC-001-1 that were addressed in
proposed Reliability Standard TOP-003-2. Concurrent with this filing, NERC is requesting withdrawal of its request
for approval of PRC-001-2 but is not proposing herein any changes to that standard. Any changes corresponding
changes to PRC-001 are being addressed in Project 2007-06.2 – Phase 2 of System Protection Coordination.

8

summary of the Commission’s concerns raised in the TOP/IRO NOPR are included in Section IV
as well as Exhibit G.
In response to the TOP/IRO NOPR, on December 20, 2013, NERC filed a motion
requesting that the Commission defer action on the Pending TOP/IRO Standards, until January 31,
2015, to allow NERC time to consider the reliability concerns raised by the Commission and revise
the Pending TOP/IRO Standards as necessary. 22 The Commission granted that motion on January
14, 2014. 23 NERC has been providing the Commission quarterly updates on the status of its
standards development process to revise the Pending TOP/IRO Standards. In its quarterly report
for the fourth quarter of 2014, filed January 2, 2015, NERC informed the Commission that it
needed additional time to obtain NERC Board of Trustees (“Board”) adoption of proposed
Reliability Standard TOP-001-3 at the Board’s regularly scheduled meeting on February 12, 2015.
D.

Project 2014-03 – Revisions to TOP and IRO Standards

In response to the TOP/IRO NOPR and consistent with NERC’s responsibility as the ERO
to develop Reliability Standards that provide for an adequate level of reliability of the Bulk-Power
System, NERC, with Commission and industry support, initiated Project 2014-03 to develop
revisions to the Pending TOP/IRO Reliability Standards and fulfill the goals of the original
projects: Project 2006-06 Reliability Coordination 24 and Project 2007-03 Real-time Operations.25

22
Motion of the North American Electric Reliability Corporation to Defer Action, Docket No. RM13-12-000
(December 20, 2013).
23

Monitoring System Conditions- Transmission Operations Reliability Standard Transmission Operations
Reliability Standards Interconnection Reliability Operations and Coordination Reliability Standards, 146 FERC ¶
61,023 (2014).
24

The Project 2006-06 development webpage is available at
http://www.nerc.com/pa/Stand/Pages/RelaibilityCoordinationProject20066.aspx.

25

The Project 2007-03 development webpage is available at http://www.nerc.com/pa/Stand/Pages/Realtime_Operations_Project_2007-03.aspx.

9

The objective of Project 2014-03 was to provide clear, unambiguous Reliability Standards to allow
Reliability Coordinators, Transmission Operators, and Balancing Authorities operate the
interconnected transmission system in a safe and reliable manner. In addition, the Project 201403 standard drafting team considered recommendations from the Independent Experts Review
Panel (“IERP”). 26
As discussed below, the proposed Reliability Standards reflect an improved, more robust
set of Reliability Standards. The NERC Board adopted the proposed Reliability Standards and
definitions on November 13, 2014, with the exception of proposed Reliability Standard TOP-0013, which the Board adopted on February 12, 2015.
JUSTIFICATION FOR APPROVAL
As discussed in Exhibit C, the proposed Reliability Standards and definitions satisfy the
Commission’s criteria in Order No. 672 and are just, reasonable, not unduly discriminatory or
preferential, and in the public interest. The development of the proposed Reliability Standards
was informed by recent industry reports and initiatives, including two NERC-sponsored technical
conferences in March 2014, 27 the Southwest Outage Report, the IERP Report, the NERC
Operating Committee consideration of the IERP report (Exhibit I), and the Commission's
TOP/IRO NOPR.
The following section provides: (1) an explanation of the purpose and improvements in the
proposed Reliability Standards and modified NERC Glossary definitions; (2) a description of each

26

In 2013, NERC formed the IERP, which consisted of five industry experts, to independently review the
NERC Reliability Standards to assess the content and quality of the Reliability Standards, including the
identification of Bulk-Power System risks. The IERP’s final report (the “IERP Report”) is available at :
http://www.nerc.com/pa/Stand/Standards%20Development%20Plan%20Library/Standards_Independent_Experts_R
eview_Project_Report.pdf.
27

The slides from the conferences are available at:
http://www.nerc.com/pa/Stand/Prjct201403RvsnstoTOPandIROStndrds/top_iro_technical_conference_presentation
_20140306.pdf.

10

of the proposed definitions and requirements in the proposed Reliability Standards; and (3) an
explanation of the manner in which the proposed Reliability Standards address the
recommendations in the Southwest Outage Report, the concerns raised in the TOP/IRO NOPR,
and outstanding FERC directives related to the proposed Reliability Standards.
A.

Purpose of and Improvements in the Proposed Reliability Standards
1.

Purpose

The proposed Reliability Standards address the important reliability goal of setting forth
the requirements applicable to Reliability Coordinators, Transmission Operators, and Balancing
Authorities with respect to planning and operating the Bulk-Power System, including requirements
for operating the interconnected transmission system within predetermined operating limits. The
proposed Reliability Standards establish or revise requirements for operations planning, system
monitoring, real-time actions, coordination between applicable entities, and operational reliability
data. The proposed Reliability Standards consolidate the currently effective TOP and IRO
Reliability Standards, providing a more precise set of Reliability Standards addressing operating
responsibilities. The mapping document, provided as Exhibit D hereto, shows how the currently
effective Reliability Standards map to the proposed Reliability Standards.
The proposed TOP Reliability Standards generally address real-time operations and
planning for next-day operations, and apply primarily to the responsibilities and authorities of
Transmission Operators. Among other things, the proposed revisions to the TOP Reliability
Standards help ensure that Transmission Operators plan to operate within all SOLs.
The proposed IRO Reliability Standards, which complement the proposed TOP Standards,
are designed to ensure that the Bulk Electric System is planned and operated in a coordinated
manner to perform reliably under normal and abnormal conditions. The proposed IRO Reliability

11

Standards set forth the responsibility and authority of Reliability Coordinators to provide for
reliable operations. Reliability Coordinators have an essential role in ensuring reliable operations,
as they are the functional entities with the highest level of authority and have the wide-area view
of the Bulk Electric System. 28
2.

Improvements

The proposed Reliability Standards improve upon the currently effective TOP and IRO
Reliability Standards by eliminating gaps, ambiguities, and redundancies, and by improving the
overall quality of the TOP and IRO Reliability Standards. Specifically, the proposed Reliability
Standards include improvements over the currently effective TOP and IRO Reliability Standards
in key areas such as: (1) operating within SOLs and IROLs; (2) outage coordination; (3) situational
awareness; (4) improved clarity and content in foundational definitions; and (5) requirements for
operational reliability data.
a)

Operating Within SOLs and IROLs

An SOL is defined in the NERC Glossary as:
The value (such as MW, MVar, Amperes, Frequency or Volts) that satisfies the
most limiting of the prescribed operating criteria for a specified system
configuration to ensure operation within acceptable reliability criteria. System
Operating Limits are based upon certain operating criteria. These include, but are
not limited to:
•
•
•
•

Facility Ratings (Applicable pre- and post-Contingency equipment or
facility ratings)
Transient Stability Ratings (Applicable pre- and post- Contingency Stability
Limits)
Voltage Stability Ratings (Applicable pre- and post- Contingency Voltage
Stability)
System Voltage Limits (Applicable pre- and post- Contingency Voltage
Limits)”

28

See Order No. 693 at P 1582 “the reliability coordinator is the highest authority in matters affecting
reliability of the Bulk-Power System.”

12

An IROL is defined as:
A System Operating Limit that, if violated, could lead to instability, uncontrolled
separation, or Cascading outages that adversely impact the reliability of the Bulk
Electric System.
As the Commission has noted, during deteriorating system conditions, an SOL can rapidly degrade
into an IROL. 29 When any Facility Rating or Stability Limit is exceeded, or expected to be
exceeded, these conditions should be mitigated to avoid the possibility of further deteriorating
system conditions and the potential for a Cascading event.
The proposed Reliability Standards improve upon existing obligations for Transmission
Operators and Reliability Coordinators to help ensure the Bulk Electric System is operated within
predetermined operating limits. Specifically, SOLs, which must be monitored by Transmission
Operators, include Ratings and limits necessary to ensure reliable operation within acceptable
reliability criteria, as determined pursuant to Facilities Design, Connections and Maintenance
(“FAC”) Reliability Standards.

In the proposed IRO Reliability Standards, Reliability

Coordinators must continue to monitor SOLs in addition to their obligation in the currently
effective Reliability Standards to monitor and analyze IROLs. These obligations require the
Reliability Coordinator to have the wide-area view necessary for situational awareness and provide
them the ability to respond to system conditions that have the potential to negatively affect reliable
operations. 30
When a Transmission Operator or Reliability Coordinator, based on its analysis and
monitoring of SOLs and/or IROLs, identify a violation of operating limits, the proposed TOP and
29

TOP/IRO NOPR at P 52.

30

See id. As the Commission noted, “[d]uring deteriorating system conditions, an SOL can rapidly degrade
into an IROL.... Major cascading events including the Northeast Blackout of 2003 and the 2011 Southwest Outage
were initiated by a non-IROL SOL exceedance, followed by a series of non-IROL SOL exceedances until the
system cascaded.” Id.

13

IRO Reliability Standards set forth the requirements for applicable entities to resolve the situation
within specified timeframes. Specifically, proposed Reliability Standard TOP-001-3 requires that
all violations of IROLs be resolved within the IROL TV, 31 which is a technically-based
performance expectation that essentially provides that IROL violations cannot exceed 30 minutes,
which is consistent with the 30-minute criteria contained in existing TOP Reliability Standards.
This proposed revision provides consistency with the Reliability Coordinator requirements
contained in currently effective Reliability Standard IRO-009-1.

The proposed Reliability

Standards also include revisions that will require resolution of SOL violations within specified
timeframes that are based on Ratings methodologies developed pursuant to the FAC Reliability
Standards and coordinated between the Transmission Operator and Reliability Coordinator.
b)

Improved Definitions

The proposed Reliability Standards also use certain foundational NERC Glossary terms,
the definitions for which have been improved as part of Project 2014-03. Specifically, NERC is
proposing revised definitions for “Operational Planning Analysis” and “Real-time Assessment.”
As described below, the proposed definitions provide significant additional detail over the
currently effective definitions to enhance the consistency and the reliability benefit of Operational
Planning Analyses and Real-time Assessments. For example, the proposed definition of Real-time
Assessment includes several inputs that were identified as contributing to past outages on the Bulk
Electric System, which, in turn, will enhance situational awareness. 32

31

IROL Tv is defined in the Glossary of Terms Used in NERC Reliability Standards as “[t]he maximum time
that an Interconnection Reliability Operating Limit can be violated before the risk to the interconnection or other
Reliability Coordinator Area(s) becomes greater than acceptable. Each Interconnection Reliability Operating Limit’s
Tv shall be less than or equal to 30 minutes.”

32

The proposed definition of Real-time Assessment is “[a]n evaluation of system conditions using Real-time
data to assess existing (pre-Contingency) and potential (post-Contingency) operating conditions. The assessment
shall reflect applicable inputs including, but not limited to: load, generation output levels, known Protection System

14

Additionally, the proposed Reliability Standards now use the proposed NERC Glossary
term “Operating Instruction” 33 instead of the term “reliability directive.” The proposed NERC
Glossary term “Operating Instruction” defines the scope of commands that are covered by the
proposed TOP and IRO Reliability Standards.
c)

Situational Awareness

The proposed Reliability Standards also improve upon existing situational awareness
requirements.

Collectively, the revised definition of Real-time Assessment and associated

requirements for Real-time monitoring and Real-time Assessments in proposed Reliability
Standards TOP-001-3 and IRO-008-2 provide for consistency in the operations of the
Transmission Operator and Reliability Coordinator, giving clear definition of responsibilities and
avoiding potential gaps.

For example, the proposed TOP Reliability Standards include a

requirement for Transmission Operators to perform Real-time Assessments at least once every 30
minutes. The requirement for Transmission Operators to assess system operating conditions on a
frequent basis, which is analogous to an existing requirement in the currently effective IRO
Reliability Standards requiring Reliability Coordinators to perform Real-time Assessments, will
improve situational awareness and reinforce the responsibilities outlined in the NERC Functional

and Special Protection System status or degradation, Transmission outages, generator outages, Interchange, Facility
Ratings, and identified phase angle and equipment limitations. (Real-time Assessment may be provided through
internal systems or through third-party services.)” Several inputs are based on the Southwest Outage Report
recommendations as described in Exhibit F.
33

The defined term “Operating Instruction” was developed along with proposed Reliability Standard COM002-4 (Operating Personnel Communications Protocol) and is currently pending before the Commission in Docket
No. RM14-13-000. See Petition of the North American Electric Reliability Corporation for Approval of Proposed
Reliability Standards COM-001-2 and COM-002-4, Docket No. RM14-13-000 (May 14, 2014). On September 18,
2014, the Commission issued a Notice of Proposed Rulemaking proposing to adopt the proposed Reliability
Standards and new proposed definitions (including Operating Instruction), as well as the implementation plans,
VRFs, and VSLs for the proposed Reliability Standards.

15

Model. 34 As noted above, the definition of Real-time Assessments has been modified to include
additional inputs to improve situational awareness.
The proposed TOP Reliability Standards also include clear requirements for monitoring
system conditions that support completion of Real-time Assessments and align with similar
requirements in the currently effective IRO Reliability Standards.

Specifically, proposed

Reliability Standard TOP-001-3 requires, among other things, Transmission Operators and
Balancing Authorities to monitor Facilities and status indications necessary to operate within SOLs
and support Interconnection frequency.
d)

Operations Planning and Outage Coordination

The proposed Reliability Standards also improve upon operational planning requirements
for Reliability Coordinators and Transmission Operators. Proposed Reliability Standards IRO008-2 and TOP-002-4 contain requirements for performing day-ahead studies and developing
plans to operate within operating limits. Certain operational planning requirements are applicable
to the Balancing Authorities as well, as discussed below. Further, the revised definition for
Operational Planning Analysis incorporates recommendations from the Southwest Outage Report
that are designed to address operations planning shortfalls with the potential to cause repeat
occurrences of similar events, as further described in Exhibit F. For example, the revised definition
of Operational Planning Analysis includes use of external system data such as transmission or
generation outages, interchange prediction, and projected system conditions to improve the scope,
accuracy, and quality of the analysis.

34

NERC Functional Model at page 38. The Transmission Operator and Reliability Coordinator have similar
roles with respect to transmission operations, but different scopes.

16

Operations planning relies on timely and accurate information of transmission and
generation outages. Consequently, the standard drafting team developed proposed Reliability
Standard IRO-017-1 to address the coordination of outages in advance. Proposed Reliability
Standard IRO-017-1 establishes operational planning requirements for each Reliability
Coordinator to implement an outage coordination process for its area that will identify and resolve
issues with the potential to impact reliable operations. Proposed Reliability Standard IRO-017-1
thus addresses a reliability gap identified in the IERP Report and the Southwest Outage Report.
e)

Operational Reliability Data

The proposed Reliability Standards establish clear requirements for the provision of
information and data needed by the Transmission Operator and Balancing Authority for reliable
operations. Effective operations planning and accurate assessment of system conditions in realtime rely on complete, current, and timely data and information. Specifically, proposed TOP-0031 establishes requirements for Transmission Operators and Balancing Authorities to specify the
data and information needed to perform their reliability functions, and obligates entities to provide
the data according to prescribed formats and protocols. In doing so, proposed TOP-003-1 is
applying the Commission-approved approach used for Reliability Coordinators in IRO-010-1a to
improve the flow of operational reliability data needed by Transmission Operators and Balancing
Authorities in a consistent manner.
B.

Proposed Reliability Standards and Definitions
1.

Proposed Definitions

NERC submits for Commission approval two revised definitions for inclusion in the NERC
Glossary: (i) Real-time Assessment, and (ii) Operational Planning Analysis. The additional
specificity reflected in the proposed definitions addresses concerns raised in the TOP/IRO NOPR

17

and recommendations in the Southwest Outage Report, as discussed below. The revisions in the
proposed definitions are intended to make sure that Operational Planning Analyses and Real-time
Assessments contain sufficient details to result in an appropriate level of situational awareness for
next-day planning and real-time operations, respectively. The current and proposed definitions of
Real-time Assessment and Operational Planning Analysis are provided below.
a)

“Real-time Assessment”

The term “Real-time Assessment” is used in the following proposed Reliability Standards:
TOP-001-3; TOP-003-3; IRO-002-4; IRO-008-2; IRO-010-2; and IRO-014-3. The term “Realtime Assessment” is currently defined in the NERC Glossary as “[a]n examination of existing and
expected system conditions, conducted by collecting and reviewing immediately available data.”
The proposed definition of “Real-time Assessment” is:
An evaluation of system conditions using Real-time data to assess existing (preContingency) and potential (post-Contingency) operating conditions. The
assessment shall reflect applicable inputs including, but not limited to: load,
generation output levels, known Protection System and Special Protection System
status or degradation, Transmission outages, generator outages, Interchange,
Facility Ratings, and identified phase angle and equipment limitations. (Real-time
Assessment may be provided through internal systems or through third-party
services.)
The proposed definition adds additional detail and clarity on the data or inputs that must
be evaluated in a Real-time Assessment.

The proposed definition will lead to improved

assessments, and, in turn, more reliable operations. The proposed definition incorporates the
defined term “Contingency” to add clarity regarding the existing and expected system conditions
that are examined in a Real-time Assessment. “Contingency” is defined in the NERC Glossary as
“[t]he unexpected failure or outage of a system component, such as a generator, transmission line,
circuit breaker, switch or other electrical element.”

The proposed definition also includes

additional specificity regarding the various inputs for the assessment and how that information
18

may be provided such as through third-party services. The use of third-party services may provide
smaller entities an efficient method for complying with the requirements.

The additional

specificity in the proposed definition ensures that assessments contain sufficient details to result
in an appropriate level of situational awareness.
b)

“Operational Planning Analysis”

The proposed definition of “Operational Planning Analysis” is used in the following
proposed Reliability Standards: TOP-002-4; TOP-003-3; IRO-002-4; IRO-008-2; IRO-010-2; and
IRO-014-3. The term “Operational Planning Analysis” is defined in the NERC Glossary as
follows:
An analysis of the expected system conditions for the next day’s operation. (That
analysis may be performed either a day ahead or as much as 12 months ahead.)
Expected system conditions include things such as load forecast(s), generation
output levels, Interchange, and known system constraints (transmission facility
outages, generator outages, equipment limitations, etc.).
The proposed definition of Operational Planning Analysis is:
An evaluation of projected system conditions to assess anticipated (preContingency) and potential (post-Contingency) conditions for next-day operations.
The evaluation shall reflect applicable inputs including, but not limited to, load
forecasts; generation output levels; Interchange; known Protection System and
Special Protection System status or degradation; Transmission outages; generator
outages; Facility Ratings; and identified phase angle and equipment limitations.
(Operational Planning Analysis may be provided through internal systems or
through third-party services.)
As with the definition of “Real-time Assessment,” the proposed definition for Operational
Planning Analysis incorporates the defined term “Contingency” to add clarity regarding the
existing and expected system conditions examined in an Operational Planning Analysis, which are
undefined in the current definition. The proposed definition also includes additional specificity
regarding the various inputs for the analysis and how that information may be provided such as
through third-party services, which may provide smaller entities an efficient method for complying
19

with the requirements.

The proposed definition removes the language specifying that the

Operational Planning Analysis may be performed “either a day ahead or as much as 12 months
ahead.” The standard drafting team concluded that the time-frame was unnecessary for the
reliability objective, which is to obtain an evaluation of projected system conditions for next-day
operations based on specified inputs.
c)

“Operating Instruction”

The NERC Glossary term “Operating Instruction”, which is currently pending Commission
approval in Docket No. RM14-13-000, is used in proposed Reliability Standards TOP-001-3 and
IRO-001-4. 35 The propose definition for the term “Operating Instruction” is as follows:
A command by operating personnel responsible for the Real-time operation of the
interconnected Bulk Electric System to change or preserve the state, status, output,
or input of an Element of the Bulk Electric System or Facility of the Bulk Electric
System. (A discussion of general information and of potential options or
alternatives to resolve Bulk Electric System operating concerns is not a command
and is not considered an Operating Instruction.)
As used in proposed Reliability Standard TOP-001-3, an Operating Instruction is the means
by which a Transmission Operator directs entities to act to address the reliability of its
Transmission Operator Area. Similarly, as used in proposed Reliability Standard, IRO-001-4, an
Operating Instruction is the means by which a Reliability Coordinator directs entities to act to
address the reliability of its Reliability Coordinator Area. It replaces the terms “directive” and
“reliability directive” used in currently effective Reliability Standards TOP-001-1a and IRO-0011.1.

35

The definition for “Operating Instruction” was developed and submitted for Commission approval along
with the proposed Reliability Standard COM-002-4 (Operating Personnel Communications Protocols). As noted
above, on September 18, 2014, the Commission issued a Notice of Proposed Rulemaking proposing to adopt the
proposed Reliability Standards and new proposed definitions (including Operating Instruction), as well as the
implementation plans, VRFs, and VSLs for the proposed Reliability Standards.

20

By focusing on commands that “change or preserve the state, status, output, or input of an
Element of the Bulk Electric System or Facility of the Bulk Electric System,” the definition does
not attempt to differentiate between commands given in an Emergency condition or a nonEmergency condition. Further, as explained in the COM-001-2 and COM-002-4 petition, a
“command,” as used in the proposed definition, purposely does not specify whether the coverage
is restricted to oral or written commands. Rather, the proposed Requirements in COM-002-4
specify protocols using the qualifiers “oral” and “written” in the Requirements themselves. As a
result, where used in the proposed TOP and IRO Reliability Standards, “Operating Instruction”
carries the broader meaning, which captures both. The proposed definition also includes a
clarifying note in parentheses that general discussions are not considered Operating Instructions.
2.

Proposed Reliability Standards
a)

Proposed Reliability Standard TOP-001-3 (Transmission
Operations)

Proposed Reliability Standard TOP-001-3 (Transmission Operations) contains twenty
requirements relating to transmission operations. As shown in Exhibit D, proposed Reliability
Standard

TOP-001-3

replaces

relevant

requirements

from

TOP-001-1a

(Reliability

Responsibilities and Authorities) and other currently effective TOP and IRO Reliability Standards
proposed for retirement. The purpose of proposed Reliability Standard TOP-001-3 is to prevent
instability, uncontrolled separation, or Cascading outages that adversely affect the reliability of the
Interconnection by ensuring prompt action to prevent or mitigate such occurrences. The proposed
standard achieves this reliability goal by providing appropriate entities with the authority to take
actions, or direct the actions of others, to maintain reliability during Real-time operations. It
includes Real-time monitoring and Real-time assessment requirements to preserve reliability and
ensure that applicable entities identify and address SOL exceedances. The proposed Reliability
21

Standard also requires entities to communicate with each other regarding issues that could affect
transmission operations. The proposed Reliability Standard applies to Balancing Authorities,
Transmission Operators, Generator Operators, and Distribution Providers. The following is a
description of each of the requirements in TOP-001-3.
Requirements R1 and R2 require each Transmission Operator (Requirement R1) and
Balancing Authority (Requirement R2) to act to address the reliability of its area through its own
actions or by issuing Operating Instructions.

These requirements establishes an explicit,

affirmative obligation to act. In contrast, as noted by the IERP, the obligation to act in currently
effective Reliability Standard TOP-001-1a is only an implied requirement.
Requirement R3 provides that each Balancing Authority, Generator Operator, and
Distribution Provider must comply with each Operating Instruction issued by its Transmission
Operator(s), unless doing so would violate safety, equipment, regulatory, or statutory
requirements or the action cannot be physically implemented.
Requirement R4 provides that each Balancing Authority, Generator Operator, or
Distribution Provider must notify the Transmission Operator if it is unable to comply with the
Transmission Operator’s Operating Instruction.
Requirements R5 requires that each Transmission Operator, Generator Operator, and
Distribution Provider comply with each Operating Instruction issued by its Balancing Authority,
unless it cannot physically implemented the action or it would violate safety, equipment,
regulatory, or statutory requirements.

22

Requirement R6 requires each Transmission Operator, Generator Operator, and
Distribution Provider to inform its Balancing Authority of its inability to comply with an
Operating Instruction issued by its Balancing Authority. 36
Requirement R7 provides that each Transmission Operator must assist other Transmission
Operators within its Reliability Coordinator Area, if requested and able, provided that the
requesting Transmission Operator has implemented its comparable Emergency procedures,
unless doing so would violate safety, equipment, regulatory, or statutory requirements or such
assistance cannot be physically implemented.

The proposed requirement creates a clear

obligation for a Transmission Operator to provide assistance within its capability (i.e. “if
requested and able”), and maintains the implicit obligation that the requesting Transmission
Operator is also taking similar action (i.e. “has implemented its comparable emergency
procedures”).
Requirement R8 provides that each Transmission Operator must inform its Reliability
Coordinator, known impacted Balancing Authorities, and known impacted Transmission
Operators of the Transmission Operator’s actual or expected operations that result in, or could
result in, an Emergency.
Requirements R9, R16, and R17 address outage coordination of monitoring and control
equipment. Proposed Requirement R9 provides that each Balancing Authority and Transmission
Operator must notify its Reliability Coordinator and known impacted interconnected entities of
all planned outages, and unplanned outages of 30 minutes or more, for telemetering and control
equipment, monitoring and assessment capabilities, and associated communication channels

36

The responsibility of Reliability Coordinators to act or direct others to act is addressed in proposed
Reliability Standard IRO-001-4 (Reliability Coordination – Responsibilities).

23

between the affected entities. Proposed Requirement R9 includes additional terms, as described
in Section IV.C below in response to the Southwest Outage Report Recommendation #15.
Proposed Requirements R16 and R17 provide that each Transmission Operator (Requirement
R16) and each Balancing Authority (Requirement R17) must provide its System Operators with
the authority to approve planned outages and maintenance.
Requirement R10 addresses Transmission Operator monitoring obligations to help ensure
that Transmission Operators have the necessary situational awareness to maintain reliable
operations. The proposed requirement is derived from currently effective Reliability Standard
IRO-003-2, Requirement R1, which covers the monitoring obligations of Reliability
Coordinators. Requirement R10 provides that each Transmission Operator must take certain steps
for determining SOL exceedances within its Transmission Operator Area. Specifically, within its
area, each Transmission Operator must monitor Facilities and the status of Special Protection
Systems. Outside its area, the Transmission Operator must obtain and use status, voltages, and
flow data for Facilities and the status of Special Protection Systems. Requirement R10 addresses
the Commission’s concerns that the Pending TOP/IRO Standards did not have sufficient
requirements for real-time monitoring. 37
Requirement R11 is the equivalent of Requirement R10 for Balancing Authorities. Under
Requirement R11, each Balancing Authority is required to monitor its Balancing Authority
Area, including the status of Special Protection Systems that impact generation or Load, in
order to maintain generation-Load-interchange balance within its Balancing Authority Area and
support Interconnection frequency.

37

TOP/IRO NOPR at P 60.

24

Requirement R12 provides that each Transmission Operator must not operate outside of
any identified IROL for a continuous duration exceeding its associated IROL Tv.
Requirement R13 provides that each Transmission Operator must ensure that a Real-time
Assessment is performed at least once every 30 minutes. This proposed requirement is derived
from Reliability Standard IRO-008-1, Requirement R2, which applies to Reliability Coordinators,
and will significantly improve situational awareness. 38
Requirement R14 provides that each Transmission Operator must initiate its Operating Plan
to mitigate a SOL exceedance identified as part of its Real-time monitoring or Real-time
Assessment. 39 As discussed below, proposed Reliability Standard TOP-002-4, Requirement R3
requires Transmission Operators to have evidence that it has an Operating Plan to address potential
System Operating Limits (SOLs) exceedances.
Requirement R15 provides that each Transmission Operator must inform its Reliability
Coordinator of actions taken to return the system to within limits when a SOL has been exceeded.
Requirement R18 provides that each Transmission Operator must operate to the most
limiting parameter in instances where there is a difference in SOLs. As shown in Exhibit D, this
Requirement is from currently effective IRO-005-3.1a, Requirement R10. The phrase “derived
limits” in IRO-005-3.1a R10 is replaced with “SOLs” for clarity and consistency.

38

As described below, proposed Reliability Standard TOP-002-4, Requirement R2 requires Transmission
Operators to have an Operating Plan for next-day operations. It is appropriate for an Operating Plan to contain
guidance for performing Real-time Assessments with detailed instructions and timing requirements to adapt to
conditions where processes, procedures, and automated software systems are not available (if used). This could
include instructions such as an indication that no actions may be required if system conditions have not changed
significantly and that previous Contingency analysis or Real-time Assessments may be used in such a situation.
39

An “Operating Plan” is defined in the NERC Glossary as:
A document that identifies a group of activities that may be used to achieve some goal. An
Operating Plan may contain Operating Procedures and Operating Processes. A company-specific
system restoration plan that includes an Operating Procedure for black-starting units, Operating
Processes for communicating restoration progress with other entities, etc., is an example of an
Operating Plan.

25

Requirements R19 and R20 provide that each Transmission Operator (Requirement R19)
and Balancing Authority (Requirement R20) must have data exchange capabilities with the entities
from which it needs data in order to maintain reliability in its area. Proposed Requirements R19
and R20 are consistent with proposed Reliability Standard IRO-002-4, Requirement R1, which
provides that each Reliability Coordinator must have data exchange capabilities with its Balancing
Authorities, Transmission Operators, and other entities it deems necessary. These data exchange
capabilities are required to support the data specifications required in proposed Reliability
Standard TOP-003-3, as discussed below.
b)

Proposed Reliability Standard TOP-002-4 (Operations Planning)

Proposed Reliability Standard TOP-002-4 (Operations Planning) contains seven
requirements relating to operations planning for Transmission Operators and Balancing
Authorities, replacing relevant requirements from Reliability Standard TOP-002-1b (Normal
Operations Planning) and other TOP and IRO Reliability Standards proposed for retirement, as
shown in Exhibit D hereto. The purpose of proposed Reliability Standard TOP-002-4 is to ensure
that Transmission Operators and Balancing Authorities have plans for operating within specified
limits. Specifically, the proposed standard addresses next-day planning and operations and
provide for the necessary notifications and coordination between various functional entities. The
revised definition of Operational Planning Analysis is an integral component of proposed TOP002-4 and specifies the scope and inputs required for next-day analyses. The proposed standard
also improves coordination of next-day operations by requiring Transmission Operators and
Balancing Authorities to provide Operating Plans to their Reliability Coordinators. Proposed
Requirements R1 through R3 and R6 apply to Transmission Operators, and proposed
Requirements R4, R5, and R7 apply to Balancing Authorities. The following is a description of

26

each of the requirements in TOP-002-4.
Requirement R1 requires each Transmission Operator to have an Operational Planning
Analysis that will allow it to assess whether its planned operations for the next day within its
Transmission Operator Area will exceed any of its SOLs.
Requirement R2 requires each Transmission Operator to have an Operating Plan (or Plans)
for next-day operations to address potential SOL exceedances identified in the Operational
Planning Analysis performed pursuant to Requirement R1.
Requirement R4 requires each Balancing Authority to have an Operating Plan (or Plans)
for the next day that address four items: (i) expected generation resource commitment and dispatch;
(ii) interchange scheduling; (iii) demand patterns; and (iv) capacity and energy reserve
requirements, including deliverability capability.
Requirements R3 and R5 require each Transmission Operator (Requirement R3) and
Balancing Authority (Requirement R5) to notify the entities identified in their Operating Plan as
to their roles in that plan.
Requirements R6 and R7 require each Transmission Operator (Requirement R6) and
Balancing Authority (Requirement R7) to provide its plan to its Reliability Coordinator.
c)

Proposed Reliability Standard TOP-003-3 (Operational Reliability
Data)

Proposed Reliability Standard TOP-003-3 (Operational Reliability Data) establishes
requirements for the provision of information and data needed by the Transmission Operator and
Balancing Authority for reliable operations, replacing relevant requirements from Reliability
Standard TOP-003-1, as shown in Exhibit D. The purpose of proposed Reliability Standard TOP003-3 is to ensure that Transmission Operators and Balancing Authorities have the data needed to
fulfill their operational and planning responsibilities. Proposed TOP-003-3 is derived from the
27

Commission-approved approach for Reliability Coordinators in Reliability Standard IRO-010-1a
to improve the flow of operational reliability data needed by Transmission Operators and
Balancing Authorities. 40
The proposed Reliability Standard consists of five Requirements, including requirements
for Balancing Authorities and Transmission Operators to maintain and distribute to relevant
entities data specifications needed to perform various analyses and assessments. The proposed
Reliability Standard also requires entities receiving data specifications to respond according to
mutually agreed upon parameters. The following is a description of each of the Requirements in
TOP-003-3.
Requirement R1 requires each Transmission Operator to maintain a documented
specification for the data necessary for it to perform its Operational Planning Analyses, Real-time
monitoring, and Real-time Assessments. The data specification must include, but is not limited
to:
•

a list of data and information needed to support these analyses, monitoring, and
assessments;

•

provisions for the notification of current Protection System and Special Protection System
status or degradation that impacts System reliability;

•

a periodicity for providing data; and

•

the deadline by which the respondent (i.e., recipient) is to provide the indicated data.
Requirement R2 requires each Balancing Authority to maintain a documented specification

for the data necessary for it to perform its analysis functions and Real-time monitoring. The data
specification must include:

40
Proposed Reliability Standard IRO-010-2 replaces Reliability Standard IRO-010-1a and contains the data
specification requirements for Reliability Coordinators.

28

•

a list of data and information needed by the Balancing Authority to support its analysis
functions and Real-time monitoring;

•

provisions for the notification of current Protection System and Special Protection System
status or degradation that impacts System reliability;

•

a periodicity for providing data; and

•

the deadline by which the respondent (i.e., recipient) is to provide the indicated data.
Requirements R3 and R4 require each Transmission Operator (Requirement R3) and

Balancing Authority (Requirement R4) to distribute its data specification to the entities that have
the necessary data.
Requirement R5 requires each Transmission Operator, Balancing Authority, Generator
Owner, Generator Operator, Load-Serving Entity, Transmission Owner, and Distribution Provider
receiving a data specification pursuant to Requirement R3 or R4 to satisfy the obligations of the
documented data specification using: (i) a mutually agreeable format; (ii) a mutually agreeable
process for resolving data conflicts; and (iii) a mutually agreeable security protocol.
Data specification and collection for Reliability Coordinators is addressed in proposed
Reliability Standard IRO-010-2 (Reliability Coordinator Data Specification and Collection),
discussed below.
d)

Proposed Reliability Standard IRO-001-4 (Reliability
Coordination – Responsibilities)

Proposed Reliability Standard IRO-001-4 (Reliability Coordination – Responsibilities)
contains requirements relating to the Reliability Coordinator’s overall responsibility for reliable
operation within the Reliability Coordinator Area. The purpose of the proposed Reliability
Standard is to establish the responsibility of Reliability Coordinators to act or direct others to act
to address the reliability of the Reliability Coordinator Area. The proposed Reliability Standard
is applicable to Reliability Coordinators, Transmission Operators, Balancing Authorities,
29

Generator Operators, and Distribution Providers, which is consistent with the entities that are listed
as receiving instructions from the Reliability Coordinator in the NERC functional model. The
Transmission Service Provider is not an applicable entity as it does not perform an operating
reliability function under the direction of the Reliability Coordinator, as described in the NERC
Functional Model.
The proposed Reliability Standard contains the following three requirements:
•

Requirement R1 provides that each Reliability Coordinator must act to address the
reliability of its Reliability Coordinator Area through direct actions or by issuing Operating
Instructions.

•

Requirement R2 provides that each Transmission Operator, Balancing Authority,
Generator Operator, and Distribution Provider must comply with its Reliability
Coordinator’s Operating Instructions unless compliance cannot be physically implemented
or such actions would violate safety, equipment, regulatory, or statutory requirements.

•

Requirement R3 provides that a Transmission Operator, Balancing Authority, Generator
Operator, or Distribution Provider informs the Reliability Coordinator that it is unable to
perform an Operating Instruction issued by its Reliability Coordinator.
e)

Proposed Reliability Standard IRO-002-4 (Reliability
Coordination – Monitoring and Analysis)

Proposed Reliability Standard IRO-002-4 (Reliability Coordination – Monitoring and
Analysis) contains requirements relating to capabilities for monitoring and analysis of Real-time
operating data. The purpose of the proposed Reliability Standard is to provide System Operators
with the capabilities necessary to monitor and analyze data needed to perform reliability functions.
The proposed Reliability Standard consists of the following four requirements:
•

Requirement R1 requires each Reliability Coordinator to have data exchange capabilities
with its Balancing Authorities, Transmission Operators, and other entities as it deems
necessary, for it to perform the Operational Planning Analyses, Real-time monitoring, and
Real-time Assessments.

•

Requirement R2 provides that each Reliability Coordinator must provide its System
Operators with the authority to approve planned outages and maintenance of its
telecommunication, monitoring, and analysis capabilities.
30

•

Requirement R3 provides that each Reliability Coordinator must monitor Facilities, the
status of Special Protection Systems, and non-Bulk Electric System facilities identified as
necessary by the Reliability Coordinator, within its Reliability Coordinator Area and
neighboring Reliability Coordinator Areas, to identify any SOL or IROL exceedances
within its Reliability Coordinator Area.

•

Requirement R4 provides that each Reliability Coordinator must have monitoring systems
that provide information used by the Reliability Coordinator’s operating personnel, with
particular emphasis to alarm management and awareness systems, automated data
transfers, and synchronized information systems, over a redundant infrastructure.
f)

Proposed Reliability Standard IRO-008-2 (Reliability Coordinator
Operational Analyses and Real-time Assessments)

Proposed Reliability Standard IRO-008-2 (Reliability Coordinator Operational Analyses
and Real-time Assessments) contains requirements for Reliability Coordinators to conduct nextday analyses and assessments of operating conditions in Real-time to help prevent instability,
uncontrolled separation, or Cascading. The proposed definitions of Operational Planning Analysis
and Real-time Assessment are integral components of proposed IRO-008-2 as they specify the
scope and inputs for next-day analysis and real-time assessments of operating conditions in Realtime. Furthermore, proposed IRO-008-2 enhances next-day operations planning by specifying
requirements for coordination of the Reliability Coordinator's Operating Plan to address potential
SOL and IROL exceedances.
The proposed Reliability Standard consists of the following six requirements, designed to
ensure that Reliability Coordinators perform analyses to identify potential or actual SOL or IROL
exceedances and that such exceedances are addressed in a coordinated fashion:
•

Requirement R1 provides that each Reliability Coordinator must perform an Operational
Planning Analysis that will allow it to assess whether the planned operations for the next
day will exceed SOLs and IROLs within its Wide Area.

•

Requirement R2 provides that each Reliability Coordinator must have a coordinated
Operating Plan for next-day operations to address potential SOL and IROLs exceedances
identified as a result of its Operating Planning Analysis performed pursuant to Requirement
R1. The coordinated Operating Plan must consider the Operating Plans provided by its
31

Transmission Operators and Balancing Authorities pursuant to Requirements R6 and R7
of proposed Reliability Standard TOP-002-4.
•

Requirement R3 provides that each Reliability Coordinator must notify impacted entities
identified in its Requirement R2 Operating Plan as to their role in the plan.

•

Requirement R4 provides that each Reliability Coordinator must ensure that a Real-time
Assessment is performed at least once every 30 minutes.

•

Requirement R5 provides that each Reliability Coordinator must notify impacted
Transmission Operators and Balancing Authorities within its Reliability Coordinator Area,
and other impacted Reliability Coordinators as indicated in its Operating Plan, when the
results of a Real-time Assessment indicate an actual or expected condition that results in,
or could result in, a SOL or IROL exceedance within its Wide Area.

•

Requirement R6 provides that each Reliability Coordinator must notify impacted
Transmission Operators and Balancing Authorities within its Reliability Coordinator Area,
and other impacted Reliability Coordinators as indicated in its Operating Plan, when the
SOL or IROL exceedance identified in Requirement R5 has been prevented or mitigated.
g)

Proposed Reliability Standard IRO-010-2 (Reliability Coordinator
Data Specification and Collection)

Proposed Reliability Standard IRO-010-2 (Reliability Coordinator Data Specification and
Collection) provides a mechanism for the Reliability Coordinator to obtain the information and
data it needs for reliable operations and to help prevent instability, uncontrolled separation, or
Cascading outages. Proposed Reliability Standard IRO-010-2 reflects recommendations from
Southwest Outage Report, including more clearly identifying necessary data and information to be
included in the Reliability Coordinator's data specification.
The proposed Reliability Standard consists of the following three requirements:
•

Requirement R1 provides that the Reliability Coordinator must maintain a documented
specification for the data necessary for it to perform its Operational Planning Analyses,
Real-time monitoring, and Real-time Assessments. The data specification must include:
o a list of data and information necessary to support Reliability Coordinator
Operational Planning Analyses, Real-time monitoring, and Real-time Assessments,
including non-Bulk Electric System data and external network data, as deemed
necessary by the Reliability Coordinator;

32

o provisions for notification of current Protection System and Special Protection
System status or degradation that impacts System reliability;
o a periodicity for providing data; and
o the deadline by which the respondent is to provide the indicated data.
•

Requirement R2 provides that the Reliability Coordinator must distribute its data
specification to entities that have the required data.

•

Requirement R3 provides that each Reliability Coordinator, Balancing Authority,
Generator Owner, Generator Operator, Load-Serving Entity, Transmission Operator,
Transmission Owner, and Distribution Provider receiving a data specification must satisfy
the obligations of the documented specifications using a mutually-agreeable format,
process for resolving data conflicts, and security protocol.
h)

Proposed Reliability Standard IRO-014-3 (Coordination Among
Reliability Coordinators)

Proposed Reliability Standard IRO-014-3 (Coordination Among Reliability Coordinators)
contains requirements for coordination for interconnected operations at the Reliability Coordinator
level.

The purpose of the proposed Reliability Standard is to ensure that each Reliability

Coordinator’s operations are coordinated such that they will not adversely affect other Reliability
Coordinator Areas and to preserve the reliability benefits of interconnected operations.
The proposed Reliability Standard consists of the following seven requirements:
•

Requirement R1 requires each Reliability Coordinator to have and implement Operating
Procedures, Processes, or Plans for activities that require notification or coordination of
actions that may affect adjacent Reliability Coordinator Areas, to support Interconnection
reliability. These Operating Procedures, Processes, or Plans must include, at a minimum:
(i) criteria and processes for notifications; (ii) energy and capacity shortages; (iii) control
of voltage, including the coordination of reactive resources; (iv) exchange of information,
including planned and unplanned outage information to support Operational Planning
Analyses and Real-time Assessments; and (v) provisions for periodic communications to
support reliable operations.

•

Requirement R2 requires each Reliability Coordinator to maintain its Operating
Procedures, Processes, or Plans through annual reviews and updates, with no more than 15
months passing between reviews. For each update, the Reliability Coordinator is required
to obtain written agreement from the other Reliability Coordinators required to take the
indicated action and distribute the Operating Procedures, Process, or Plans within 30 days
of an update.
33

•

Requirement R3 requires each Reliability Coordinator to notify other impacted Reliability
Coordinators upon identification of an expected or actual Emergency in its Reliability
Coordinator Area.

•

Requirement R4 specifies that, in the event Reliability Coordinators disagree on the
existence of an Emergency, each impacted Reliability Coordinator must operate as though
an Emergency exists.

•

Requirement R5 provides that each Reliability Coordinator that identifies an Emergency in
its Reliability Coordinator Area must develop an action plan to resolve the Emergency.

•

Requirement R6 provides that each impacted Reliability Coordinator must implement the
action plan developed by the Reliability Coordinator that identifies the Emergency, unless
such actions would violate safety, equipment, regulatory, or statutory requirements.

•

Requirement R7 requires each Reliability Coordinator to assist other Reliability
Coordinators, if requested and able, provided that the requesting Reliability Coordinator
has implemented its Emergency procedures, unless such actions cannot be physically
implemented or would violate safety, equipment, regulatory, or statutory requirements. The
proposed requirement creates an affirmative obligation for the Reliability Coordinator to
provide assistance within its capability (i.e. “if requested and able”), and maintains the
implicit obligation that the requesting Reliability Coordinator is also taking similar action
(i.e. ‘has implemented its emergency procedures”).
i)

Proposed Reliability Standard IRO-017-1 (Outage Coordination)

Proposed Reliability Standard IRO-017-1 (Outage Coordination) is a new Reliability
Standard designed to ensure that outages are properly coordinated in the Operations Planning time
horizon and Near-Term Transmission Planning Horizon. 41 Transmission Planning and Operations
Planning involve different functional entities per the NERC Functional Model. Furthermore, these
two types of planning involve different objectives, information, timeframes, and processes. The
requirements in the proposed Reliability Standard, which span both time horizons, provide the
necessary requirements for effective coordination of planned outages to support reliable
operations.

41

The Operations Planning time horizon refers to “operating and resource plans from day-ahead up to and
including seasonal.” See Time Horizons, available at http://www.nerc.com/files/Time_Horizons.pdf. The term
Near-Term Transmission Planning Horizon is defined in the NERC Glossary as “[t]he transmission planning period
that covers Year One through five.”

34

Proposed Reliability Standard IRO-017-1 consists of the following four requirements to
address planned outage coordination concerns.
•

Requirement R1 provides that each Reliability Coordinator must develop, implement, and
maintain an outage coordination process for generation and Transmission outages within
its Reliability Coordinator Area. This process must:
o identify applicable roles and reporting responsibilities, including development and
communication of outage schedules and assignment of coordination responsibilities
for outage schedules between Transmission Operators and Balancing Authorities;
o specify outage submission timing requirements;
o define the process to evaluate the impact of Transmission and generation outages
with the Reliability Coordinator’s Wide Area; and
o define the process to coordinate the resolution of identified outage conflicts with
Transmission Operators and Balancing Authorities, as well as other Reliability
Coordinators.

•

Requirement R2 provides that each Transmission Operator and Balancing Authority must
perform the functions specified in its Reliability Coordinator’s outage coordination
process.

•

Requirement R3 provides that each Planning Coordinator and Transmission Planner must
provide its Planning Assessment to impacted Reliability Coordinators. 42 Planning
Coordinators and Transmission Planners are required to develop Planning Assessments
under the currently effective Reliability Standard TPL-001-4 (Transmission System
Planning Performance Requirements).

•

Requirement R4 requires each Planning Coordinator and Transmission Planner to jointly
develop solutions with its respective Reliability Coordinator(s) for identified issues or
conflicts with planned outages in its Planning Assessment for the Near-Term Transmission
Planning Horizon.
C.

Consideration of the Southwest Outage Report Recommendations

The following section discusses the manner in which the proposed Reliability Standards
address the recommendations of the Southwest Outage Report. On the afternoon of September 8,
2011, an 11-minute system disturbance occurred in the Pacific Southwest, leading to cascading

42
Planning Assessment is defined in the NERC Glossary as a “[d]ocumented evaluation of future
Transmission System performance and Corrective Action Plans to remedy identified deficiencies.”

35

outages and leaving approximately 2.7 million customers without power (“2011 Southwest
Outage”). The outages affected parts of Arizona, southern California, and Baja California,
Mexico. All of the San Diego area lost power, with nearly 1.5 million customers in the region
losing power, some for up to 12 hours. 43
Following the 2011 Southwest Outage, NERC and FERC conducted a joint investigation.
The investigation concluded that the cause of the disturbance stemmed primarily from weaknesses
in operations planning and real-time situational awareness, which, if conducted properly, would
have allowed system operators to proactively operate the system in a secure state during normal
system conditions and to restore the system to a secure state as soon as possible. 44
On April 27, 2012, FERC and NERC issued the Southwest Outage Report, outlining the
investigators’ findings and making recommendations for reliability improvements. The Southwest
Outage Report made twenty-seven (27) findings and associated recommendations applicable
mostly to Transmission Operators, Balancing Authorities, and Reliability Coordinators. These
findings and recommendations addressed the lack of adequate operations planning and real-time
situational awareness of contingency conditions, as well as other factors that contributed to the
2011 Southwest Outage. 45 The Southwest Outage Report findings are divided into eight

43

Southwest Outage Report at 1.

44

Id. at 5.

45
The Southwest Outage Report concluded that several other factors contributed to the 2011 Southwest
Outage. For example, the Reliability Coordinator and the affected entities did not consistently recognize the adverse
impact that sub-100 kV facilities can have on the Bulk-Power System reliability. Furthermore, there were
significant issues with Protection System settings. See Southwest Outage Report pp. 63-110 and Appendix B: Table
of Findings and Recommendations.

36

categories,

46

and each category lists specific reliability issues identified during the joint

investigation.
As part of Project 2014-03, the standard drafting team considered the Southwest Outage
Report findings and recommendations applicable to Transmission Operators, Balancing
Authorities and Reliability Coordinators, and addressed these recommendations in the language of
the proposed Reliability Standards. 47 Several of the findings and recommendations were outside
the scope of Project 2014-03 either fully, or partially, as discussed in this section of the petition.48
Below is a short description of each applicable finding and recommendation identified in the
Southwest Outage Report, 49 and an explanation of how the proposed Reliability Standards address
the reliability issues identified following the 2011 Southwest Outage. The full listing of the
recommendations and mapping to the proposed TOP and IRO Reliability Standards is provided in
Exhibit F. A summary of the findings and recommendations is available in Appendix B of the
Southwest Outage Report.

46

The eight categories of findings are: next-day planning, seasonal planning, near-and long-term planning,
situational awareness, consideration of Bulk Electric System equipment, Interchange System Operating Limits
(IROLs) derivations, Protection Systems, and angular separation. See Southwest Outage Report, Appendix B.
47

See Exhibit F Mapping of Revised TOP and IRO Reliability Standards to Address 2012 Southwest Outage
Report Recommendations (“Southwest Outage Recommendation Mapping Document”). Several of the Southwest
Outage Report recommendations were specific to the particular facts and circumstances of the 2011 Southwest
Outage, and were not addressed in the Southwest Outage Recommendation Mapping Document. The Southwest
Outage Report identified weaknesses in WECC seasonal planning, but the standard drafting team determined that
these weaknesses should not become prescriptive requirements for all Reliability Coordinator areas.

48

Id.

49

See Southwest Outage Report, Appendix B for a list of all findings and recommendations included in the
Southwest Outage Recommendation Mapping Document and this petition.

37

1.

Operations Planning

Eight findings in the Southwest Outage Report relate to operations planning. 50 The
Southwest Outage Report’s next-day and seasonal planning recommendations fall within this
category and were considered together by the standard drafting team.
As described more fully below, the Southwest Outage Report recommendations related to
operations planning are addressed generally by proposed Reliability Standards IRO-017-1, TOP002-4 and IRO-008-2.

Proposed Reliability Standard IRO-017-1 addresses the outage

coordination concerns identified in the Southwest Outage Report, as its purpose is to ensure that
outages are properly coordinated in the Operations Planning Time Horizon and Near-Term
Transmission Planning Horizon. Outage coordination in the Operations Planning Time Horizon
supports the needs of the Transmission Operators and the Reliability Coordinators to plan for
reliable next-day operations, as required by the proposed TOP-002-4 and IRO-008-2. Specific
considerations related to each finding are included below.
Finding #1: Failure to Conduct and Share Next-Day Studies
The Southwest Outage Report concluded that not all of the affected Transmission
Operators conduct next-day studies or share their studies with the neighboring Transmission
Operator and the Reliability Coordinator. Accordingly, recommendation #1 suggested that all
Transmission Operators should conduct next-day studies and share the results with neighboring
Transmission Operators and the Reliability Coordinator (before the next day). This measure was
proposed to ensure that all contingencies that could affect the Bulk-Power System are studied.

50

The standard drafting team referenced the definition of “Operations Planning Time Horizon” to group
items. This definition includes “operating and resource plans from day‐ahead up to and including seasonal.”

38

The proposed language of TOP-002-4, Requirements R1, R3, and R6 directly addresses
this recommendation by requiring Transmission Operators to conduct next-day studies
(Requirement R1), share the results of the studies with the registered entities identified in the
Operating Plan(s) (Requirement R3), and provide the results to the Reliability Coordinator
(Requirement R6).
Finding #2: Lack of Updated External Networks in Next-Day Study Models
The Southwest Outage Report determined that when conducting next-day studies, some
affected Transmission Operators used models that do not reflect next-day operating conditions
external to their systems. Recommendation #2 stated that Transmission Operators and Balancing
Authorities update their studies to reflect these conditions. Such external operating conditions
include generation and transmission outages and scheduled Interchanges.
Proposed Reliability Standards TOP-002-4, Requirement R1 and TOP-003-3 Requirement
R1, Part 1.1, and the proposed definition of Operational Planning Analysis address this particular
reliability concern. Specifically, TOP-002-4 Requirement R1 requires the Transmission Operators
to have Operational Planning Analysis for the next day, which under the proposed definition
includes external operating conditions like Interchange data, transmission and generator outages,
and identified equipment limitations. In addition, proposed Reliability Standard TOP-003-3
Requirement R1, Part 1.1 requires Transmission Operators to maintain a documented specification
for the data they need to support Operational Planning Analyses, including external network data.
Furthermore, recommendation #2 suggested that Transmission Operators and Balancing
Authorities should take the necessary steps to allow free exchange of next-day operational data
between operating entities. TOP-003-3 Requirements R1, R2 and R5 address this reliability issue.
Requirement R1 directs Transmission Operators to maintain data specification for the data

39

necessary to perform Operational Planning Analysis, and Requirement R2 establishes a similar
obligation for Balancing Authorities.

Requirement R5 requires Transmission Operators,

Balancing Authorities, Generator Owners, Generator Operators, Load-Serving Entities,
Transmission Owners, and Distribution Providers to satisfy any requests for information included
in the proposed Reliability Standard that are necessary for completion of the required Operational
Planning Analysis.
The same recommendation also concluded that the Reliability Coordinators should review
the procedures for coordinating next-day studies within their region, ensure adequate data
exchange among Balancing Authorities and Transmission Operators, and facilitate the next-day
studies conducted by Balancing Authorities and Transmission Operators. This issue is addressed
in proposed IRO-008-2 R2, which directs Reliability Coordinators to have coordinated Operating
Plans(s) for next-day operations. These coordinated Operating Plans aim to timely and adequately
address reliability issues identified in the next-day Operational Planning Analysis.
Finding #3: Sub-100 kV Facilities not Adequately Considered in Next-Day
Studies
In the Southwest Outage Report, NERC and FERC staff determined that in conducting
next-day studies, some Transmission Operators do not adequately consider lower-voltage facilities
below 100 kV.

Recommendation #3 stated that Transmission Operators and Reliability

Coordinators should ensure their next-day studies include all internal and external facilities
(including those below 100 kV) that can affect Bulk-Power System reliability. Proposed TOP003-3 R1.1 and IRO-010-2 R1.1 address this by specifically requiring Transmission Operators and
Reliability Coordinators to incorporate any non-Bulk Electric System data deemed necessary into
their Operational Planning Analyses, Real-time monitoring, and Real-time Assessments.

40

Finding #4: Flawed Process for Estimating Scheduled Interchanges
During the 2011 Southwest Outage investigation, NERC and FERC staff determined that
the Reliability Coordinator process for estimating scheduled Interchanges was not adequate to
ensure that such values were accurately reflected in the Reliability Coordinator’s next-day studies.
Recommendation #4 suggested that the Reliability Coordinator involved in the event should
improve its process for predicting Interchanges in the day-ahead timeframe. In the proposed
definition of Operational Planning Analysis, Interchange data is an included input of next-day
studies, which addresses this recommendation.
Finding #5: Lack of Coordination in Seasonal Planning Process
The Southwest Outage Report concluded that due to a lack of coordination in the seasonal
planning process in the Western Electricity Coordinating Council (“WECC”) region, Transmission
Operators may fail to identify contingencies in one subregion that could affect other Transmission
Operators in the same or another subregion.

Recommendation #5 addresses this issue by

recommending that the individual Transmission Operators should conduct a full contingency
seasonal analysis to identify contingencies outside their own systems and share the analysis with
the other affected Transmission Operators. 51
Proposed Reliability Standards TOP-003-3, Requirement R1 and TOP-002-4, Requirement
R3 address coordination of operational planning among Transmission Operators by requiring
Transmission Operators to gather external data deemed necessary to perform analysis and share
the results of the studies with the affected entities. Furthermore, proposed Reliability Standard
IRO-017-1 requires Reliability Coordinators to establish an outage coordination process that will

51

This recommendation also included language related to actions of the WECC Regional Entity. This section
of the recommendation was not considered by the standard drafting because it is not applicable to Reliability
Coordinators, Transmission Operators and Balancing Authorities and falls outside the scope of Project 2014-03.

41

identify and resolve transmission and generation planned outage issues in the Operations Planning
Time Horizon, which includes next-day and seasonal planning periods that have the potential to
impact the Reliability Coordinator’s wide-area.
Finding #6: External and Lower-Voltage Facilities not Adequately Considered in
Seasonal Planning Process
The Southwest Outage Report concluded in recommendation #6 that the focus of
Transmission Operator seasonal planning should be expanded to include external facilities and
internal and external sub-100 kV facilities that affect Bulk-Power System reliability. This
reliability concern is addressed in TOP-003-3, Requirement R1, which requires Transmission
Operators to obtain external network and sub-100 kV data deemed necessary for use in Operational
Planning Analyses. Additionally, the outage coordination process established by Reliability
Coordinators, as required by proposed IRO-017-1, must specifically address wide-area issues. In
this manner, the proposed Reliability Standards collectively ensure that the scope of operations
planning from day-ahead up to and including seasonal planning extends beyond the individual
Transmission Operator Area and is coordinated across the Reliability Coordinator Area.
Furthermore, proposed Reliability Standard IRO-017-1, Requirement R1 specifies that the
Reliability Coordinator’s outage coordination process must include a process for resolving planned
outage conflicts with other Reliability Coordinators.
Finding #7: Failure to Study Multiple Load Levels
The Southwest Outage Report determined that Transmission Operators in WECC do not
always conduct their individual planning studies based on multiple base cases, and as a result,
some contingencies could be missed and excluded from the studies. FERC and NERC staff
suggested in recommendation #7 that Transmission Operators include in their seasonal studies
multiple base cases and generation maintenance outages, as well as dispatch scenarios during high42

load shoulder periods. The standard drafting team addressed this issue by including a broader
definition of Operational Planning Analysis, under which projected system conditions such as load
forecasts and generation output levels must be considered by Transmission Operators and
Reliability Coordinators. Such projected system conditions would include generator outages and
high-load periods.

Additionally, the outage coordination process established by Reliability

Coordinators as required by proposed IRO-017-1 must specifically define a process to evaluate the
impact of transmission and generation planned outages within the wide-area. The Reliability
Coordinator’s outage coordination process covers the Operations Planning Time Horizon, which
spans from day-ahead up to and including seasonal planning.
Finding #8: Not Sharing Overload Relay Trip Setting
Recommendation #8 of the Southwest Outage Report recommended that Transmission
Operators include in the information they share during the seasonal planning process the overload
relay trip settings on transformers and transmission lines that affect the Bulk-Power System. This
reliability concern is addressed in proposed Reliability Standards TOP-003-3, Requirement R1
and TOP-002-4, Requirement R3, and in the associated definition of Operational Planning
Analysis. TOP-003-3, Requirement R1 requires Transmission Operators to maintain provisions
for notification of current Protection System and Special Protection System status or degradation
that affects system reliability. The proposed Reliability Standard TOP-002-4, Requirement R3
requires sharing of the study results among the Transmission Operators.

Furthermore, the

definition of Operational Planning Analysis explicitly requires that Protection Systems be included
in the pre-and-post contingency studies.
Additionally, the Reliability Coordinators must specifically define a process to evaluate
the impact of transmission and generation planned outages within the wide-area as required by
proposed IRO-017-1. This process would include relevant system inputs necessary to evaluate the
43

impact of transmission and generation planned outages on the reliable operation of the Bulk Power
System.

The Reliability Coordinator’s outage coordination process covers the Operations

Planning Time Horizon, which spans from day-ahead up to and including seasonal planning.
2.

Near-and-long term planning

Finding #9: Gaps in Planning Process
Recommendation #9 of the Southwest Outage Report recommended that Transmission
Operators 52 develop study cases that cover critical system conditions over the planning horizon;
consider the benefits and potential adverse effects of all Protection Systems, including remedial
action schemes (RASs), Safety Nets (such as the San Onofre Nuclear Generating Station (SONGS)
separation scheme), and overload protection schemes; study the interaction of RASs and Safety
Nets; and consider the impact of elements operated at less than 100 kV on Bulk-Power System
reliability. This reliability concern is addressed in proposed Reliability Standard TOP-003-3,
Requirement R1, Part 1.1 and 1.2 and the proposed definition of Operational Planning Analysis,
as discussed above.
3.

Situational Awareness

Finding #11: Lack of Real-Time External Visibility
NERC and FERC staff concluded in the Southwest Outage Report that Transmission
Operators have limited real-time visibility outside their systems and lack adequate situational
awareness of external contingencies.

Accordingly, recommendation #11 proposed that

Transmission Operators engage in more real-time data sharing and obtain sufficient data to monitor
significant external facilities in real-time. Proposed Reliability Standard TOP-003-3 addresses

52

This recommendation is also applicable to Planning Coordinators and Transmission Planners, which fall
outside the scope of Project 2014-03. Recommendation #9 includes language applicable specifically to WECC
Regional Entity, which is also outside the scope of the proposed Reliability Standards. Recommendation #10 is not
applicable and was not considered by the standard drafting team.

44

this issue by requiring Transmission Operators to include external network data in their data
specifications for Operational Planning Analyses.
In addition, recommendation #11 advised that Transmission Operators review their realtime monitoring tools, such as state estimator and real-time contingency analysis (“RTCA”), to
ensure that such tools reflect the critical facilities needed for the reliable operation of the Bulk
Power System. The language in proposed Reliability Standard TOP-001-3, Requirement R13
addresses this reliability concern by requiring Transmission Operators to perform a Real-time
Assessment at least once every 30 minutes. Furthermore, the proposed definition of Real-time
Assessment includes an assessment of potential post-contingency operating conditions.
Finding #12: Inadequate Real-Time Tools
In recommendation #12, FERC and NERC staff advised that Transmission Operators
should take measures to ensure that their real-time tools are adequate, operational, and run
frequently enough to provide their operators the situational awareness necessary to identify and
plan for contingencies and reliably operate their systems. Proposed Reliability Standard TOP001-3, Requirement R13, as described in detail above, is designed to resolve this specific issue by
requiring Transmission Operators to ensure a Real-time Assessment is performed at least once
every 30 minutes.
Finding #13: Reliance on Post-Contingency Mitigation Plans
The Southwest Outage Report determined that post-contingency mitigation plans are not
viable under all circumstances and suggested in recommendation #13 that Transmission Operators
review existing operating processes and procedures to ensure that post-contingency mitigation
plans reflect the time necessary to take mitigating actions to return the system to a secure state.
Proposed Reliability Standards TOP-002-4, Requirement R2 and TOP-001-3, Requirement R14
resolve this issue by requiring Transmission Operators to have an Operating Plan to address SOL
45

exceedances, and initiate the Operating Plan to mitigate an exceedance as part of its real-time
monitoring or assessment.
In addition, the standard drafting team has developed a white paper on SOL definition and
exceedance criteria (the “SOL White Paper”), which clarified the standard drafting team’s position
on establishing and exceeding SOLs, and on implementing Operating Plans to mitigate
exceedances. 53 The SOL White Paper provides important linkages between relevant reliability
standards and reliability concepts to establish a common understanding necessary for developing
effective Operating Plans to mitigate SOL exceedances.
Finally, recommendation #13 advised that as part of the review of existing operating
processes and procedures, Transmission Operators should consider the effect of relays that
automatically isolate facilities without providing operators sufficient time to take mitigating
measures. This reliability concern is addressed in proposed Reliability Standard TOP-003-3,
Requirement R1, and the proposed definitions of Operational Planning Analysis and Real-time
Assessment, which collectively require the acquisition of Protection System data, such as relays
that automatically isolate facilities, as an item to be included in the TOP studies.
Finding #15: Failure to Notify WECC Reliability Coordinator and the
Neighboring Transmission Operators Upon Losing Real Time Contingency
Analysis (RTCA) Capability
During the 2011 Southwest Outage, at least one affected Transmission Operator lost the
ability to conduct RTCA more than 30 minutes prior to, and throughout the course of the event.
As a result, recommendation #15 suggested that Transmission Operators should ensure procedures

53

System Operating Limit Definition and Exceedance Clarification, White Paper (May 2014). Available at:
http://www.nerc.com/pa/Stand/Prjct201403RvsnstoTOPandIROStndrds/2014_03_first_posting_white_paper_sol_ex
ceedance_20140509.pdf

46

and training 54 are in place to notify WECC Reliability Coordinator and neighboring Transmission
Operators and Balancing Authorities promptly after losing RTCA capabilities. Proposed TOP001-3, Requirement R9, which requires Transmission Operators to notify affected registered
entities of outages to monitoring and assessment capabilities, addresses this recommendation.
4.

Consideration of Bulk Electric System Equipment

Designation of Bulk Electric System facilities is outside the scope of Project 2014-03. The
proposed Reliability Standards incorporated non-Bulk Electric System data and facilities
monitoring where necessary for the reliable operation of the Bulk Electric System, as shown
below.
Finding #17: Impact of Sub-100 kV Facilities on Bulk Power System Reliability
The Southwest Outage Report determined that WECC Reliability Coordinator and affected
Transmission Operators and Balancing Authorities did not consistently recognize the adverse
impact sub-100 kV facilities could have on Bulk-Power System reliability. Recommendation #17
concluded that WECC, as the Reliability Coordinator, should lead other entities, including
Transmission Operators and Balancing Authorities, to ensure that all facilities that can adversely
impact Bulk-Power System reliability are either designated as part of the Bulk Electric System or
otherwise incorporated into planning and operations studies, and actively monitored and alarmed
in RTCA systems.
With respect to sub-100 kV facilities, the standard drafting team determined that any sub100 kV elements that is necessary for reliable operation of the Bulk Electric System would be
included as Bulk Electric System facilities through the exception process provided in Appendix

54

The training issue falls outside of the scope of Project 2014-03.

47

5C to the NERC Rules of Procedure. 55

The exception process provides the means for

Transmission Operators and Reliability Coordinators to include Elements in the Bulk Electric
System that are necessary for the reliable operation of the interconnected transmission system but
were not identified in the Bulk Electric System definition. 56 Accordingly, the standard drafting
team concluded it is unnecessary to include non-Bulk Electric System monitoring. In addition,
proposed Reliability Standard TOP-001-3, Requirement R10 requires Transmission Operators to
monitor Facilities within their Transmission Operator Area, and to obtain information deemed
necessary by the Transmission Operator about such Facilities located outside of the Transmission
Operator Area when determining SOL exceedances.
When non-Bulk Electric Facilities have no impact on the Bulk Electric System, but are
needed for completing system models, then the Commission-approved FAC-001-2, Requirement
R3 addresses the issue. This Reliability Standard requires the Reliability Coordinator to include
in its methodology its entire Reliability Coordinator Area and critical modeling details from other
Reliability Coordinator Areas that would affect the Facility under study.

In addition, the

Reliability Coordinator must include details of system models used to determine SOLs.

55
Revisions to Electric Reliability Organization Definition of Bulk Electric System and Rules of Procedure,
Order No. 773, 141 FERC ¶ 61,236 (2012), order on reh’g, Order No. 773-A, 143 FERC ¶ 61,053 (2013), order on
reh’g and clarification, 144 FERC ¶ 61,174 (2013); Revisions to Electric Reliability Organization Definition of Bulk
Electric System and Rules of Procedure, 143 FERC ¶ 61,231, at P 13 (2013).
56

In approving the exception process, the Commission stated:
We believe that entities, having knowledge of their systems and the concomitant planning
assessments and system impact studies, will identify an element that is necessary for reliable
operation of the integrated transmission network while conducting their day-to-day operations and
planning and performing studies. If the element does not fall within the definition, we expect that
the entity will submit the element for inclusion through the exception process. Use of this process
should ensure that the all sub-100 kV elements, as well as other facilities, necessary for the
operation of the interconnected transmission network are included in an 'appropriate and
consistent' manner.

Order No. 773 at P 269.

48

Similarly, proposed Reliability Standard IRO-002-4, Requirement R4 requires each
Reliability Coordinator to monitor facilities identified as necessary within its Reliability
Coordinator Area and within neighboring Reliability Coordinator Areas, and to identify any SOL
exceedances and to determine any IROL exceedances.
Finally, as noted above, the proposed Reliability Standards TOP-003-3, Requirement R1
and IRO-010-2, Requirement R1 incorporate non-Bulk Electric System facilities into the data used
by Transmission Operators and Reliability Coordinators to support their analysis.
5.

Interconnection Reliability Operating Limit Derivations

Finding #18: Failure to Establish Valid SOLs and Identify IROLs
Recommendation #18.1 of the Southwest Outage Report advised that Reliability
Coordinators study IROLs in the day-ahead timeframe and monitor potential IROL exceedances
in real-time. Reliability Standard FAC-014-2, Requirement R1 directs the Reliability Coordinator
to establish SOLs and IROLs. To address the recommendation, proposed Reliability Standard
IRO-008-2, Requirement R1 further specifies that each Reliability Coordinator shall perform an
Operational Planning Analysis that will allow it to assess whether the planned operations for the
next-day will exceed SOLs and IROLs within its wide-area. In addition, IRO-008-2, Requirement
R4 requires the Reliability Coordinator to perform a Real-time Assessment of system conditions
at least once every 30 minutes.
6.

Protection Systems

Findings #19-#26: Related to Coordination of Special Protection Systems and
Remedial Action Schemes at the Reliability Coordinator and TOP level
The standard drafting team determined that currently effective Reliability Standard PRC001 already addresses coordination of Special Protection Systems and Remedial Action Schemes.
Thus, any changes to Protection System coordination falls outside the scope of Project 2014-3.
49

Nevertheless, proposed Reliability Standards TOP-001-3, Requirement R10 and IRO-002-4,
Requirement R4 address monitoring of Special Protection Systems and Remedial Action
Schemes. 57 TOP-001-3, Requirement R10 Part 10.1 mandates Transmission Operators to monitor
Facilities and the status of Special Protection Systems within their Transmission Operator areas,
while Part 10.2 mandates the same actions for Facilities outside of a Transmission Operator’s area.
7.

Angular Separation

Findings #27: Phase Angle Difference Following Loss of Transmission Line
The Southwest Outage Report concluded that one of the Transmission Operators involved
in the 2011 Southwest Outage did not have tools in place to determine the phase angle difference
between the two terminals of its 500 kV line after the line tripped. Recommendation #27 included
several possible actions to address this failure, including a suggestion that the Transmission
Operators should have the tools necessary to evaluate phase angle differences following the loss
of lines. Although the recommended changes related to phase angle calculation tools fall outside
the scope of Project 2014-3 as it is being addressed in Project 2009-02 Real-time Reliability
Monitoring and Analysis Capabilities, the proposed definition of Operational Planning Analysis
and Real-time Assessment include consideration of phase angle and equipment limitations.
D.

Consideration of TOP/IRO NOPR Concerns

In its TOP/IRO NOPR, the Commission expressed certain concerns regarding the Pending
TOP/IRO Standards and proposed to remand those standards for further consideration in NERC’s

57

During the development of the proposed TOP/IRO standards, the terms Remedial Action Scheme and
Special Protection System were interchangeable as defined in the NERC Glossary of Terms. On February 3, 2015
NERC filed a petition for approval of revisions to the definition of “Remedial Action Scheme” (“RAS”), which
proposes to eliminate the defined term Special Protection System. See RM15-13-000. Proposed TOP/IRO
standards will be modified as necessary based on the Commission's action in response to NERC's petition in RM1513-000.

50

standards development process. 58 The Commission identified “Issues to be addressed” and “Issues
Requiring Clarifications.” As part of Project 2014-03, the standard drafting team considered the
issues raised in the TOP/IRO NOPR and designed the proposed Reliability Standards to address
the Commission’s concerns. This section discusses the manner in which the proposed Reliability
Standards address each of the issues raised in the TOP/IRO NOPR. Additional information is
provided in Exhibit G hereto.
1.

TOP Reliability Standards – Issues to be Addressed
a. Plan and Operate Within All SOLs

The Commission expressed concern that the Pending TOP/IRO Standards lacked a
requirement for Transmission Operators to analyze and operate within all SOLs. 59 Specifically,
the Commission stated that while the Pending TOP/IRO Standards require Transmission Operators
to plan to operate within all IROLs, they only require Transmission Operators to plan to operate
within a limited subset of SOLs identified by the Transmission Operator as necessary to support
reliability internal to its area. 60 The Commission maintained that this limitation would reduce
system reliability and cause negative consequences external to the Transmission Operator’s area. 61
The Commission also expressed the concern that deteriorating system conditions may result in an
SOL rapidly degrading into an IROL. The Commission noted further that limiting the analysis to
non-IROL SOLs identified internally by the Transmission Operator may “reduce system reliability
because operators have less situational awareness of the system and conditions.” 62

58

TOP/IRO NOPR at PP 42-99.

59

Id. at P 42.

60

Id.

61

Id. at PP 42, 51.

62

Id. at P 52.

51

The proposed Reliability Standards address the Commission’s concerns by requiring
Transmission Operators to plan to operate within all SOLs. Proposed Reliability TOP-001-3,
Requirement R14 requires “each Transmission Operator to initiate its Operating Plan to mitigate
an SOL exceedance identified as part of its Real-time monitoring or Real-time Assessment.”
Further, proposed TOP-001-3, Requirement R15 requires that each Transmission Operator inform
its Reliability Coordinator of actions taken to resolve the SOL exceedance. Proposed IRO-008-2,
Requirements R1, R2, R5, and R6 now include coverage of SOLs, which resolves the
Commission’s concern that the previously-proposed Reliability Standards limited “non-IROL
SOLs” to only those internally identified by the Transmission Operator.
The Commission also proposed that the Transmission Operator should be required “to have
an operational plan to operate within all Bulk-Power System IROLs and SOLs for all cases when
facility ratings or stability limits are exceeded during anticipated normal and contingency event
conditions.” 63 The Commission noted that this operational plan “is needed to ensure that a
Transmission Operator operates in, or can return its system to, a reliable operating state” and that
a Transmission Operator should have plans for all Bulk-Power System IROLs and SOLs that can
be implemented within 30 minutes or less to return the system to a secure state. 64
To address the Commission’s concerns, 65 proposed Reliability Standard TOP-002-4
requires, among other things, that Transmission Operators have: (1) an Operational Planning
Analysis that will allow it to assess whether its planned operations for the next day within its
Transmission Operator Area will exceed any of its SOLs; and (2) an Operating Plans for next-day
operations to address potential SOL exceedances identified as a result of its Operational Planning

63

TOP/IRO NOPR at P 54.

64

Id. at P 54.

65

Id.

52

Analysis. Further, as noted above, proposed Reliability TOP-001-3, Requirement R14 requires
Transmission Operators to initiate their Operating Plans to mitigate any SOL exceedances
identified as part of its Real-time monitoring or Real-time Assessment.”
The Commission also raised the concern that the Pending TOP/IRO Standards do not
consider the possibility that additional SOLs could develop or occur in the same-day or Real-time
operational time horizon, and therefore would pose an operational risk to the interconnected
transmission network. 66 The Commission's concern is addressed in proposed Reliability Standard
TOP-001-3, where operational responsibilities and actions pertaining to IROLs and SOLs are
established for the real-time operational time horizon.
2.

TOP Reliability Standards – Issues Requiring Clarification 67
a. System Models, Monitoring and Tools

The Commission raised a concern about NERC’s proposed retirement (on redundancy
grounds) of TOP Reliability Standards associated with system computer models, monitoring
equipment, metering, and analysis tools. The Commission stated that
[m]onitoring and analysis capabilities are essential in establishing and maintaining
situational awareness. While NERC indicates that these functions are assured
through the certification process, we are not convinced that NERC’s certification
process is a suitable substitute for a mandatory Reliability Standard. . . .
[C]ertification is a one-time process that may not adequately assure continual
operational responsibility would occur if these requirements were in a Reliability
Standard. 68

66

TOP/IRO NOPR at P 55.

67

In addition to the Issues Requiring Clarification discussed below, the Commission requested clarification
on issues related to Reliability Standard PRC-001. As discussed above, issues related to PRC-001 are being
addressed in a separate project.
68

TOP/IRO NOPR at P 60.

53

The Commission stated that the retirement of certain requirements in the currently effective IRO
and TOP Reliability Standards addressing monitoring and analysis capabilities should not occur
before the completion of NERC Project 2009-02. 69
Proposed Reliability Standard TOP-001-3, Requirements R10 and R11 address this
concern by adapting currently effective Reliability Standard IRO-003-2, Requirement R1 to
Transmission Operators and Balancing Authorities. Specifically, TOP-001-3, Requirement R10
obligates each Transmission Operator to determine SOL exceedances within its Transmission
Operator Area by monitoring facilities and the status of Special Protection Systems, and obtaining
and using status, voltages and flow data for facilities and the status of Special Protection Systems
outside of its Transmission Operator Area. Similarly, Requirement R11 directs each Balancing
Authority to monitor its Balancing Authority Area, including the status of Special Protection
Systems that affect generation or load, to maintain generation-load-interchange balance within its
Balancing Authority Area and support interconnection frequency. Further, proposed Reliability
Standard TOP-001-3, Requirement R13 also adapt currently effective Reliability Standard
IRO-008-1, Requirement R2 to the Transmission Operator, requiring each Transmission Operator
to perform a Real-time Assessment at least once every 30 minutes.
The proposed changes to Reliability Standard TOP-001-3, Requirements R10, R11 and
R13 address the Commission’s concerns about the retirement of the currently effective IRO and
TOP requirements creating gaps on monitoring and analysis capabilities before the completion of
Project 2009-02. Therefore, NERC does not propose a schedule as directed by the Commission to
complete and implement Project 2009-02 prior to retiring these requirements. 70

69

TOP/IRO NOPR at P 61.

70

Id.

54

b. Compliance with Reliability Directives
The Commission expressed concern with NERC’s proposed definition of “Reliability
Directive” that could be interpreted as limiting the obligation to comply with Transmission
Operator directives in emergencies only. 71 As discussed above, the proposed Reliability Standards
used the proposed term “Operating Instruction” to provide additional clarity and specification to
the circumstances under which entities must comply with a Transmission Operator’s commands.
c. Consideration of External Networks and sub-100 kV Facilities and
Contingencies in Operational Planning Analysis
The Commission expressed concerns that the Pending TOP/IRO Standards were unclear
on the need for including external networks or sub-100 kV facilities in the Operational Planning
Analysis conducted by Transmission Operators. 72 The proposed TOP Reliability Standards
address this concern as follows.

Proposed Reliability Standard TOP-003-3 requires each

applicable entity to develop a data specification that would cover its data needs for monitoring and
analysis purposes, including non-Bulk Electric System data and external network data deemed
necessary by the Transmission Operator to support its Operational Planning Analyses, Real-time
monitoring, and Real-time Assessments (see Requirement R1, Part 1.1). Further proposed TOP003-3, Requirement R5 requires Transmission Operators to supply data to Transmission Operator,
thus making it clear that a Transmission Operator may request and receive data from outside of its
immediate area. Similar requirements are proposed in IRO-010-2, Requirement R1, Part 1.1 for
Reliability Coordinators.

71

TOP/IRO NOPR at P 64.

72

Id. at P 68.

55

The Commission also noted that Order No. 693 contained a directive to modify the TOP
Reliability Standards for planned outage coordination to consider sub-100 kV facilities that the
registered entity viewed as having a direct impact on Bulk-Power System reliability. 73 The
Southwest Blackout Report recommended similar treatment of sub-100 kV facilities and external
networks to ensure that Transmission Operators’ next-day studies include all external networks
and facilities that could affect the reliability of the Bulk-Power System. 74 Proposed Reliability
Standard IRO-017-1 addresses outage coordination among the Reliability Coordinator,
Transmission Operator, Balancing Authority, Planning Coordinator, and Transmission Planner.
Together with the data specification requirements in proposed Reliability Standards TOP-003-3
and IRO-010-2, proposed Reliability Standard IRO-017-1 would help ensure that the outage
coordination process established by Reliability Coordinator will consider sub-100 kV facilities
that the relevant entities view as having a direct impact on Bulk-Power System reliability.
d. Operating to Respect the Most Severe Single Contingency in Real-Time
Operations and Unknown Operating States
In the NOPR, the Commission expressed concern with the proposed retirements of TOP004-2, Requirements R2 and R4, which include “three key rules, the requirements to be ready for
the single largest contingency, to move quickly from an ‘unknown operating state’ to within
proven limits, and to determine the cause of SOL violations in all time-frames, including realtime.” 75 The proposed Reliability Standards maintain the reliability objective of operating to the
most severe single contingency by requiring monitoring, notification, and actions to operate within

73

See TOP/IRO NOPR at P 68 (citing Order No. 693 at P 1624).

74

See Id. at P 68 (citing 2011 Southwest Outage Report, recommendation Nos. 2 and 3).

75

Id. at P 73. The Commission stated that “these three rules represent the bedrock core of real-time
operating rules and practices, and it is therefore incumbent upon NERC to provide a more thorough and
comprehensive explanation of how the proposed replacement standards compare in meeting the same objectives as
the current standards.”

56

SOLs and IROLs as discussed in preceding sections. Further, the FAC Reliability Standards
currently require that SOLs provide a certain level of Bulk Electric System performance for the
pre- and post-Contingency state.

Additionally, the proposed definitions of “Real-time

Assessment” and “Operational Planning Analysis” are strengthened to include Contingency
conditions in the evaluations as follows:
An evaluation of projected system conditions to assess anticipated (preContingency) and potential (post-Contingency) conditions for next-day operations.
The evaluation shall reflect applicable inputs including, but not limited to, load
forecasts; generation output levels; Interchange; known Protection System and
Special Protection System status or degradation; Transmission outages; generator
outages; Facility Ratings; and identified phase angle and equipment limitations.
(Operational Planning Analysis may be provided through internal systems or
through third-party services.)
The proposed Reliability Standards require Transmission Operators to plan to operate
within SOLs and to initiate Operating Plans to mitigate SOL exceedances. The Commission noted
that a reliability objective should be to move quickly from an ‘unknown operating state’ to within
proven limits. 76 The standard drafting team considers that, operationally, there always will be
limits in service, and an operator should be obligated to adhere to the set of limits in service at the
time a situation arises. The Commission’s concern about an “unknown operating state” is
addressed in proposed Reliability Standard TOP-001-3 and the SOL White Paper, attached as
Exhibit E hereto, which explains how an SOL exceedance is determined and what entities do upon
experiencing such an exceedance. Proposed Reliability Standard TOP-001-3, Requirement R13
specifies that Transmission Operators must perform a Real-time Assessment at least once every
30 minutes, which by definition is an evaluation of system conditions to assess existing (preContingency) and potential (post-Contingency) operating conditions. The Real-time Assessment

76

TOP/IRO NOPR at P. 73

57

provides the Transmission Operator with the necessary knowledge of the system operating state to
initiate an Operating Plan, as specified in Requirement R14, when necessary to mitigate an
exceedance of SOLs, as described in the SOL White Paper. The SOL White Paper provides
technical guidance for including timelines in the required Operating Plans to return the system to
within prescribed ratings and limits.
Further, proposed Reliability Standard TOP-001-3, Requirements R12 and R13 address
this concern by prohibiting a Transmission Operator from operating outside any IROL for a
continuous duration exceeding its associated IROL Tv (Requirement R12), and requiring that a
Transmission Operator perform a Real-time Assessment at least once every 30 minutes
(Requirement R13).
The Commission noted that importance of determining ‘the cause of SOL violations in all
time-frames, including real-time.” Proposed Reliability Standard TOP-001-3, Requirement R10
addresses this point by ensuring appropriate action is taken to mitigate an exceedance, but does
not specifically require that the cause of the violation must be determined in real-time. Instead,
real-time efforts should be focused on resolving the exceedance with causes investigated,
analyzed, and determined later and off-line. Pursuant to the revised definition of Real-time
Assessment and proposed TOP-001-3, Requirement R13, which requires that a Transmission
Operator perform a Real-time Assessment at least every 30 minutes, NERC believes that the Realtime Assessment conducted by Transmission Operators is sufficient for identifying “cause” for
operators in Real-time.
Questions posed by the Commission with regard to the impact and usefulness of the
proposed Real-time Assessment on smaller entities, who often maintain similar reliability based

58

on operator experience, 77 are also addressed by the flexibility that provided in proposed Reliability
Standard TOP-001-3, Requirement R13. Requirement R13 requires that a Real-time Assessment
be performed every 30 minutes or less, but it does not mandate how it should be done. This
requirement would allow smaller entities the flexibility to devise their own methods to comply
with the requirement, including contracting with others to provide these services on their behalf.
e. Notification of Emergencies
In the NOPR, the Commission identified potential inconsistencies and ambiguities
resulting from terminology used in the Pending TOP standards. 78 Proposed Reliability Standard
TOP-001-3 uses the defined term “Emergency” in places where the Commission identified
ambiguity, and applies the term to all operating time horizons. Further, the term Adverse
Reliability Impact was eliminated from the proposed standard.
f. Primary Decision-Making Authority for Mitigation of IROLs/SOLs
The Commission sought clarification and technical explanation of whether Transmission
Operators or Reliability Coordinators have primary responsibility for IROLs. 79 NERC hereby
clarifies that the Reliability Coordinator has primary responsibility for IROLs, and the
Transmission Operator has primary responsibility for SOLs, although the Reliability Coordinator
must provide oversight on SOLs, as well as assistance in mitigating SOLs, as necessary. This split
in responsibilities is important for the preservation of reliability within the Bulk Electric System

77

TOP/IRO NOPR at P 74.

78

Id. at P 80-83.

79

Id. at P 87.

59

and consistent with the NERC functional model. The proposed Reliability Standards were
designed to be consistent with these roles.
3.

IRO Reliability Standards – Issues to be Addressed
a. Planned Outage Coordination

The Commission identified coordination of outages as “a critical reliability function that
should be performed by the Reliability Coordinator” that is not adequately addressed in the
Pending TOP/IRO Standards.

80

Proposed Reliability Standard IRO-017-1 addresses the

Commission’s NOPR concerns. Under the proposed standard, each Reliability Coordinator is
required to develop, implement and maintain an outage coordination process for generation and
transmission outages in its Reliability Coordinator Area.

Each Transmission Operator and

Balancing Authority, in turn, would be required to perform the functions specified in its Reliability
Coordinator’s process. Further, each Planning Coordinator and Transmission Planner will provide
its Planning Assessment to relevant Reliability Coordinators and work together to solve any issues
or conflicts with planned outages among the applicable entities. Additionally, proposed Reliability
Standard IRO-014-3, Requirement R1, Part 1.4 requires Reliability Coordinators to include the
exchange of planned and unplanned outage information to support Operational Planning Analyses
and Real-time Assessments in the Operating Procedures, Processes, and Plans for activities that
require coordination with adjacent Reliability Coordinators.

80

TOP/IRO NOPR at P 90.

60

4.

IRO Reliability Standards – Issues Requiring Clarification
a. Use of a Secure Data Network

The Commission sought assurance that the Pending TOP/IRO Standards provided for data
exchange and notifications among Reliability Coordinators, Transmission Operators and
Balancing Authorities “using a secure mode in a secure environment.” 81 Proposed Reliability
Standard TOP-003-3, Requirement R5, Part 5.3 and proposed IRO-010-2, Requirement R3, Part
3.3 specify that security is to be part of a data specification, and to be mutually agreed upon by the
applicable registered entities. This proposed change makes clear that the data exchange and
notifications among Reliability Coordinators, Transmission Operators, and Balancing Authorities
“will be conducted using a secure mode in a secure environment.”
b. Reliability Coordinator Monitoring of SOLs and IROLs
The Commission expressed concerns with proposed changes to the obligation of Reliability
Coordinators to monitor SOLs in the currently effective IRO Reliability Standards. 82 The
proposed Reliability Standards maintain the obligations for Reliability Coordinators to monitor
SOLs. Specifically, proposed Reliability Standard IRO-002-4, Requirement R3 requires each
Reliability Coordinator to monitor facilities, Special Protection Systems, and necessary non-Bulk
Electric System facilities in order to identify SOL and IROL exceedances within its Reliability
Coordinator Area.
E.

Consideration of Outstanding Commission Directives

In developing the proposed Reliability Standards, the standard drafting team also addressed
outstanding Commission directives relevant to the proposed Reliability Standards. Exhibit H

81

TOP/IRO NOPR at P 94.

82

Id. at P 96.

61

hereto provides a list of these outstanding directives and a description of the manner in which the
standard drafting team addressed these directives. The following is a brief discussion of how the
proposed Reliability Standards address the notable outstanding directives.
1. Outstanding Directives Related to the IRO Reliability Standards
•

The Commission directed NERC to consider clarifying the requirement in IRO-001-1 that
entities comply with a Reliability Coordinator’s directive “unless such actions would
violate safety, equipment or regulatory or statutory requirements.” 83 As discussed above,
that requirement is carried forward in proposed Reliability Standard IRO-001-4. The
standard drafting team clarified during the development of the standard that the term
“safety” should be read broadly to encompass the safety of both personnel and equipment
and that no additional wording is needed.

•

The Commission also directed NERC to consider stakeholder comments regarding the
establishment of a chain of command so that, for example, if a Generator Operator receives
conflicting instructions from a Balancing Authority and a Transmission Operator, it can
determine which instruction governs. 84 The standard drafting team concluded that no
additional medications to the proposed Reliability Standards are necessary. If Generator
Operator receives conflicting Operating Instructions, the Generator Operator should
contact the Reliability Coordinator for clarification. The NERC Functional model refers
to the Reliability Coordinator as overall authority.

•

The Commission also directed NERC to consider stakeholder comments that Reliability
Standard IRO-001-1 fails to address the operational limitations of qualifying facilities
(“QFs”) because QFs have contractual obligations to provide thermal energy to their
industrial hosts and can only be directed to change operations only in the case of a system
emergency, pursuant to 18 CFR § 292.307. 85 The standard drafting team concluded that
no modifications to the proposed Reliability Standards were necessary because while a
Reliability Coordinator can direct a QF to act in accordance with an Operating
Instructions, the proposed Reliability Standards do not require a QF to comply if it would
violate the QFs regulatory or statutory requirements.

•

The Commission directed NERC to modify Reliability Standard IRO-002-1 to require a
minimum set of tools that must be made available to the Reliability Coordinator. 86 This
directive was beyond the scope of Project 2014-03 and is being addressed in a separate

83

Order No. 693 at P 897.

84

Id. at P 897.

85

Id.

86

Id. at P 905.

62

standards development project (Project 2009-02 Real-time Reliability Monitoring and
Analysis Capabilities).
•

The Commission directed NERC to develop a modification to Reliability Standard IRO003-1 to create criteria to define the term “critical facilities” in a Reliability Coordinator’s
area and its adjacent systems. 87 The proposed Reliability Standards no longer use the term
“critical facilities.” As discussed above, proposed Reliability Standard IRO-010-2
provides a mechanism for Reliability Coordinators to obtain data necessary to perform its
reliability tasks, obviating the need for specific criteria for determining critical facilities.

•

The Commission directed NERC to modify Reliability Standard IRO-004-1 to require the
next-day analysis to identify control actions that can be implemented and effective within
30 minutes after a contingency. 88 As described above, this issue is addressed in proposed
Reliability Standards IRO-008-2 and TOP-002-4, as well as through the revised
definitions of Operational Planning Analysis and Real-time Assessment. In short, SOLs
must be controlled according to the Operating Plan, which is set up on time-based facility
ratings. IROLs are controlled to the IROL Tv, which by definition is always less than 30
minutes. Commission-approved Reliability Standard IRO-009-1, also addresses this issue.

•

The Commission directed NERC to include a requirement for the Reliability Coordinator
to assess and approve actions that have impacts beyond the area views of Transmission
Operators or Balancing Authorities, including how to determine whether an action needs
to be assessed by the Reliability Coordinator. 89 Proposed Reliability Standard IRO-0082, Requirements R2 and R5 address this directive by requiring Reliability Coordinators to
(1) have coordinated Operating Plans for next-day operations, and (2) notify impacted
Transmission Operators, Balancing Authorities and other Reliability Coordinators when
the results of a Real-time Assessment indicate an actual or expected condition that results
in, or could result in, a SOL or IROL exceedance within its Wide Area.

•

The Commission directed NERC to provide clarification in proposed standards that
Reliability Coordinators and Transmission Operators direct control actions of entities in
their respective areas to respect System Operating Limits and Interconnection Reliability
Operating Limits. 90 Proposed Reliability Standard IRO-001-4 Requirement R1 addresses
this clarification in the case of the Reliability Coordinator as discussed above. (TOP-0013 Requirement R1 addresses this clarification in the case of the Transmission Operator).

•

In Order No. 693, the Commission also directed NERC to include the Reliability
Coordinator as an applicable entity in Reliability Standard VAR-001-1 given its role as
the highest level of authority overseeing the reliability of the Bulk-Power System. 91

87

Order No. 693 at P 914.

88

Id. at P 935.

89

Id. at P 525.

90

Id. at P 950.

91

Id. at P 1855.

63

Although the directive related to the VAR standards, because the IRO standards address
the Reliability Coordinator’s oversight of Bulk-Power System facilities, the standard
drafting team concluded that this directive is addressed in proposed Reliability Standard
IRO-002-4, Requirement R3, which requires the Reliability Coordinator to monitor
facilities, which would include voltage and reactive power resources.
•

Similarly, the Commission directed NERC to develop a modification to INT-006-1 that
makes it applicable to Reliability Coordinators and Transmission Operators, requiring
them to review energy interchange transactions from the wide-area and local area
reliability viewpoints, respectively, and, where their review indicates a potential
detrimental reliability impact, communicate to the sink Balancing Authorities necessary
transaction modifications before implementation. 92 Proposed Reliability Standard IRO008-2 addresses this directive by requiring Reliability Coordinators to perform an
Operational Planning Analysis, which requires Reliability Coordinators to consider
Interchange, and develop a plan to address any problems. Similar requirements exist for
the Transmission Operator in proposed Reliability Standard TOP-002-3.

•

Directives pertaining to Reliability Standard PRC-001 93 are being addressed in a separate
project to revise that standard.
2. Outstanding Directives Related to the TOP Reliability Standards

•

The Commission directed to NERC to modify TOP-001-1 to define the term
“emergency.” 94 Proposed TOP-001-3 uses the defined term “Emergency” to improve
clarity. The standard drafting team concluded that criteria for entering operating states
belong in EOP standards, as noted by the Commission in Order 693. 95 Currently
enforceable Reliability Standard EOP-002-3.1 - Capacity and Energy Emergencies and
proposed Reliability Standard EOP-011-1 contain responsibilities.

•

The Commission directed to NERC to consider stakeholder comments to require the
Transmission Operator to notify the Reliability Coordinator or the Balancing Authority
that it is removing facilities from service. 96 This directive is addressed in proposed
Reliability Standard TOP-001-3, Requirement R8, which requires Transmission Operators
to inform its Reliability Coordinator, known impacted Balancing Authorities, and known
impacted Transmission Operators of its actual or expected operations that result in, or
could result in, an Emergency.

92

Order No. 693 at P 866.

93

Id. at P 1449.

94

Id. at P 1585.

95

Id. at P 560.

96

Id. at P 1588.

64

•

The Commission directed revisions to TOP-002-2 and TOP-005-1 to deletes references to
confidentiality agreements in Requirements R3 and R4, but addresses the issue separately
to ensure that necessary protections are in place related to confidential information. 97 As
discussed above, proposed Reliability Standards IRO-010-2 and TOP-003-3 address
security of data.

•

The Commission directed revisions to TOP-002-2 to require the next-day analysis for all
IROLs to identify and communicate control actions to system operators that can be
implemented within 30 minutes following a contingency to return the system to a reliable
operating state and prevent cascading outages. 98 As IROLs are the responsibility of the
Reliability Coordinator, this issue is addressed in proposed Reliability Standard IRO-0082 and Commission-approved Reliability Standard IRO-009-1, as discussed above.

•

The Commission directed revisions to TOP-002-2 to require next-day analysis of
minimum voltages at nuclear power plants auxiliary power busses. 99 This issue is
addressed through proposed Reliability Standards IRO-010-2 and TOP-003-3, which
provide Reliability Coordinators and Transmission Operators, respectively, a mechanism
to acquire all of the data necessary for them to fulfill their reliability functions including
non-Bulk Electric System data, as necessary. Next-day analysis is performed using
Operational Planning Analysis.

•

The Commission directed revisions to TOP-002-2 to also require simulation contingencies
to match what will actually happen in the field. 100 The standard drafting team revised the
definitions of Operational Planning Analysis and Real-time Assessment accordingly to
require Contingencies to match field conditions.

•

The Commission directed NERC to revise TOP-003-0 to require the communication of
scheduled outages to all affected entities well in advance to ensure reliability and accuracy
of available transmission capability calculations. 101 Proposed Reliability Standard IRO017-1 addresses this directive by requiring Reliability Coordinators to develop,
implement, and maintain an outage coordination process for generation and Transmission
outages within its Reliability Coordinator Area.

•

The Commission also directed NERC to revise TOP-003-0 to incorporate an appropriate
lead-time for planned outages. 102 The standard drafting team determined that such a
requirements is not necessary and could potentially conflict with existing rules in

97

Order No. 693 at PP 1608, 1651.

98

Id. at P 1608.

99

Id.

100

Id.

101

Id. at P 1620.

102

Id. at P 1621.

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organized markets. Nevertheless, pursuant to proposed Reliability Standard IRO-017-1,
a Reliability Coordinator could include lead times in its process.
•

The Commission directed NERC to consider whether to include breaker outages within
the meaning of facilities that are subject to advance notice for planned outages. 103 Pursuant
to IRO-017-1, a Reliability Coordinator could include breakers in its outage coordination
process.

•

The Commission also directed modifications to TOP-003-0 to require that any facility
below the thresholds in Requirement R1 of that standard that, in the opinion of the
Transmission Operator, Balancing Authority, or Reliability Coordinator will have a direct
impact on the reliability of the Bulk-Power System be subject to planned outage
coordination. 104 Under proposed Reliability Standards IRO-010-2 and TOP-003-3, the
Reliability Coordinator and Transmission Operator have a mechanism to obtain the data
necessary to perform their reliability tasks, including identifying the appropriate facilities
for outage coordination.

•

The Commission directed modification to TOP-004-1 to require that the system be
restored to respect proven limits as soon as possible taking no more than 30 minutes.105
This directive is addressed through the more stringent definitions proposed for Operational
Planning Analysis, Real-time Assessment, and the requirements in proposed Reliability
Standard TOP-004-2 for the Transmission Operator to perform an Operational Planning
Analysis as well as a Real-time Assessment every 30 minutes and to create an Operating
Plan for mitigation of SOL exceedances.

•

The Commission also directed revisions to TOP-004-1 to explicitly incorporate the
interpretation of “multiple outages” as multiple element outages resulting from high-risk
conditions. 106 The standard drafting team concluded that Commission-approved
Reliability Standard EOP-001-2.1b, which covers emergency operations planning, already
addresses this directive. In addition, Commission-approved Reliability Standard FAC011-2 and FAC-014-2 includes specific requirements for dealing with multiple
contingencies.

•

The Commission also directed NERC to consider stakeholder comments that TOP-004-1,
Requirement R2 should be revised to include frequency monitoring. 107 This directive is
addressed by proposed Reliability Standards IRO-010-2 and TOP-003-3, which provide
Reliability Coordinators and Transmission Operators a mechanism to obtain data on
frequency, voltages, real and reactive power flows, and any other data that the entity needs.

103

Order No. 693 at P 1622.

104

Id. at P 1624.

105

Id. at P 1636.

106

Id. at P 1638.

107

Id. at P 1639.

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•

The Commission directed revisions to TOP-005-1 regarding the operational status of
special protection systems and power system stabilizers. 108 The standard drafting team
addressed this directive in proposed Reliability Standards IRO-010-2 and TOP-003-3 and
in revising the definitions of Operational Planning Analysis and Real-time Assessments.
Proposed Reliability Standards IRO-010-2 and TOP-003-3 specifically include a
requirement to have provisions for notification of current Protection System and Special
Protection System status or degradation.

•

The Commission directed revisions to TOP-005-1 to add a requirement related to the
provision of minimum capabilities that are necessary to enable operators to deal with realtime situations and to ensure reliable operation of the Bulk-Power System. 109 This
directive was beyond the scope of Project 2014-03 and will be addressed in a future
standards development project (Project 2009-02 Real-time Monitoring and Analysis
Capabilities).

•

The Commission directed NERC to clarify the meaning of “appropriate technical
information” concerning protective relays as used in TOP-006-1. 110 That term is not used
in the proposed Reliability Standards. To address concerns about the status of protection
systems, the standard drafting team incorporated explicit references in the definitions of
Operational Planning Analysis and Real-time Assessment and the data specification
standards (i.e., proposed Reliability Standards IRO-010-2 and TOP-003-3).

•

The Commission directed NERC to consider the Nuclear Energy Regulatory
Commission’s comments related to nuclear power plant voltage requirements. 111 Under
proposed Reliability Standards TOP-002-3 and TOP-001-3, applicable entities must study
minimum voltage limits, including those at nuclear plants.
In addition to the directives addressed by the standards drafting team, discussed above,

NERC also notes that it resolved two directives from Order No. 748 112 that relate to the issues
addressed by the proposed Reliability Standards. First, the Commission directed the NERC
Reliability Coordinator Working Group to consider whether the need exists to refine the
delineation of responsibilities between the Reliability Coordinator and Transmission Operator for

108

Order No. 693 at P 1648.

109

Id. at PP 1660, 1875.

110

Id. at P 1665.

111

Id. at P 1673.

112

Mandatory Reliability Standards for Interconnection Reliability Operating Limits, Order No. 748, 134
FERC ¶ 61,213 (2011).

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analyzing certain “grid-impactive” SOLs that are of interest to the Reliability Coordinator. 113
Second, the Commission directed the NERC Reliability Coordinator Working Group to consider
whether there is a need for reliability coordinators to have action plans developed and implemented
with respect to certain “grid-impactive” SOLs that are of interest to the Reliability Coordinator. 114
The working group, which included participation from the NERC Operating Committee
and stakeholders, concluded that there was no need to create another category between IROL and
SOL called “grid-impactive” SOLs. The working group determined that such a category could not
be clearly defined and consequently did not support changes to the currently effective IRO
standards. In addition to the working group action, the directives are addressed by proposed IRO008-2 Requirements R1 and R2, which require the Reliability Coordinator to (1) analyze both
SOLs and IROLs, as discussed above, and (2) must have a coordinated operating plan to address
potential SOL and IROL exceedances which considers the operating plans provided by the
Transmission Operators.
F.

Enforceability of Proposed Reliability Standards

The proposed Reliability Standards also include measures that support each requirement
by clearly identifying what is required and how the ERO will enforce the requirement. These
measures help ensure that the requirements will be enforced in a clear, consistent, and nonpreferential manner and without prejudice to any party. 115
The proposed Reliability Standards also include VRFs and VSLs. The VRFs and VSLs
provide guidance on the way that NERC will enforce the requirements of the proposed Reliability
Standards. The VRFs and VSLs for the proposed Reliability Standards comport with NERC and

113

Order No. 748 at P 44.

114

Id. at P 55.

115

Order No. 672 at P 327.

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Commission guidelines related to their assignment. Exhibit J provides a detailed review of the
VRFs and VSLs, and the analysis of how the VRFs and VSLs were determined using these
guidelines.
CONCLUSION
For the reasons set forth above, NERC respectfully requests that the Commission approve:
•

the proposed Reliability Standards and associated elements included in Exhibit A;

•

the proposed revised definitions to be incorporated into the NERC Glossary, included
in Exhibit A; and

•

the proposed Implementation Plan, including the noted retirements, included in Exhibit
B.
Respectfully submitted,
/s/ Shamai Elstein
Holly A. Hawkins
Associate General Counsel
Shamai Elstein
Senior Counsel
North American Electric Reliability Corporation
1325 G Street, N.W., Suite 600
Washington, D.C. 20005
(202) 400-3000
holly.hawkins@nerc.net
shamai.elstein@nerc.net
Counsel for the North American Electric Reliability
Corporation

Date: March 18, 2015

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