Agenda Standards Committee Conference Call Highlights and...2020/06/17 · were Dan Custer (MidAmerican Energy), Terry Volmann (Volkmann Consulting, Inc.), Guy Zito (NPCC), Ruth Kloecker

RELIABILITY | RESILIENCE | SECURITY

Agenda Standards Committee Conference Call June 17, 2020 | 1:00―3:00 p.m. Eastern Dial-in: 1-415-655-0002 | Access Code: 479 557 704 | Meeting Password: 061720 Click here for: WebEx Access Introduction and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement* NERC Participant Conduct Policy Agenda Items

1. Review June 17 Agenda ― Approve (A. Casuscelli) (1 minute)

2. Consent Agenda (A. Casuscelli) (5 minutes)

a. April 22, 2020 Standards Committee Meeting Minutes* ― Approve

3. Projects Under Development ― Review

a. Project Tracking Spreadsheet (C. Yeung) (5 minutes)

b. Projected Posting Schedule (H. Gugel) (5 minutes)

4. Project 2015-09 Establish and Communicate System Operating Limits* ― Authorize (S. Kim) (10 minutes)

a. IRO-008-3 Clean

b. IRO-008-3 Redline to approved

c. TOP-001-6 Clean

d. TOP-001-6 Redline to approved

5. Project 2019-06 Cold Weather Nominations* ― Authorize (S. Kim) (15 minutes)

6. Project 2020-01 Modifications to MOD-032 Nominations* CONFIDENTIAL ― Appoint (S. Kim) (15 minutes)

7. Standards Committee Member Training Documentation* ― Endorse (A. Casuscelli) (15 minutes)

8. Legal Update and Upcoming Standards Filings* ― Review (M. Hecht) (5 minutes)

9. Informational Items ― Enclosed

a. Standards Committee Expectations*

b. 2020 SC Meeting Schedule

https://nerc.webex.com/nerc/onstage/g.php?MTID=e6d9908fb8b00cb8746e89639535064ba

https://www.nerc.com/gov/Annual%20Reports/NERC%20Antitrust%20Compliance%20Guidelines.pdf

https://www.nerc.com/gov/Annual%20Reports/NERC_Participant_Conduct_Policy.pdf

https://www.nerc.com/comm/SC/Project%20Management%20and%20Oversight%20Subcommittee%20DL/Project%20Tracking%20Spreadsheet.xlsx

http://www.nerc.com/pa/Stand/Documents/Projected_Posting_Schedule.pdf

https://www.nerc.com/comm/SC/Documents/2020%20SC%20Meeting%20Schedule.pdf

Agenda – Standards Committee Meeting – June 17, 2020 2

c. 2020 Standards Committee Roster

d. Highlights of Parliamentary Procedure*

10. Adjournment

*Background materials included.

https://www.nerc.com/comm/SC/Documents/2020%20SC%20Roster.pdf


Public Meeting Notice REMINDER FOR USE AT BEGINNING OF MEETINGS AND CONFERENCE CALLS THAT HAVE BEEN PUBLICLY NOTICED AND ARE OPEN TO THE PUBLIC Conference call/webinar version: As a reminder to all participants, this webinar is public. The registration information was posted on the NERC website and widely distributed. Speakers on the call should keep in mind that the listening audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders. Face-to-face meeting version: As a reminder to all participants, this meeting is public. Notice of the meeting was posted on the NERC website and widely distributed. Participants should keep in mind that the audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders. For face-to-face meeting, with dial-in capability: As a reminder to all participants, this meeting is public. Notice of the meeting was posted on the NERC website and widely distributed. The notice included the number for dial-in participation. Participants should keep in mind that the audience may include members of the press and representatives of various governmental authorities, in addition to the expected participation by industry stakeholders.


Agenda Item 2a Standards Committee

June 17, 2020

Minutes Standards Committee Conference Call April 22, 2020 | 1:00–3:00 p.m. Eastern A. Casuscelli, chair, called to order the meeting of the Standards Committee (SC or the Committee) on April 22, at 1:00 p.m. Eastern. C. Larson, secretary, called roll and determined the meeting had a quorum. The SC member attendance and proxy sheets are attached as Attachment 1. NERC Antitrust Compliance Guidelines and Public Announcement The Committee secretary called attention to the NERC Antitrust Compliance Guidelines and the public meeting notice and directed questions to NERC’s General Counsel, Sonia C. Mendonça. Introduction and Chair’s Remarks A. Casuscelli welcomed the Committee and guests, and acknowledged the people attending as proxies. Review April 22, 2020 Agenda (agenda item 1) The Committee approved the April 22, 2020 meeting agenda by unanimous consent. Consent Agenda (agenda item 2) The Committee approved the March 18, 2020 SC meeting minutes by unanimous consent. Projects Under Development (agenda item 3) C. Yeung reviewed the Project Tracking Spreadsheet. He highlighted relevant information for each project L. Oelker asked about the status of Project 2015-09 for the additional standards that did not pass the first ballot, and specifically about whether ‘SOL Methodology’ will be a new defined term. S. Kim clarified that there will be additional postings for the previously balloted standards. H. Gugel reviewed the Projected Posting Schedule. H. Gugel shared additional information about the reoccurring NERC Five Year Performance Assessment with FERC, and specifically about the process for developing Reliability Guidelines. S. Bodkin asked if future project postings will be spread out a bit considering the current pandemic. B. Lawson echoed the comments made by S. Bodkin. Project 2015-09 System Operating Limits (agenda item 4) S. Kim provided a background regarding the Project 2015-09 posting, which includes standards posted for additional comment period and ballot in addition to the standards NERC requests the Committee to authorize for initial posting. B. Lawson asked if the Committee can authorize the posting, but then delay the posting. L. Oelker was concerned that the term ‘SOL Methodology’ is not a defined term in the Glossary of Terms, and called out potential inconsistencies in the capitalization of the terms. J. Babik stated he believed ‘SOL Methodology’ should be a defined term. SOL Methodology is defined in FAC-011 R1, ‘The Reliability Coordinator shall have a documented methodology for use in developing SOLs (SOL Methodology) within its Reliability Coordinator Area.’ V. Greaff questioned whether the current SAR gives the SDT the latitude to propose a new definition for SOL Methodology.

http://www.nerc.com/comm/SC/_layouts/xlviewer.aspx?id=/comm/SC/Project%20Management%20and%20Oversight%20Subcommittee%20DL/Project%20Tracking%20Spreadsheet.xlsx&Source=http%3A%2F%2Fwww%2Eqa%2Enerc%2Ecom%2Fcomm%2FSC%2FProject%2520Management%2520and%2520Oversi






Minutes – Standards Committee Meeting | April 22, 2020 2

L. Oelker moved to remand the Project 2015-09 posting to create consistent use of the term ‘SOL Methodology’ or ‘SOL methodology’. The Committee approved the motion with C. Yeung objecting, and no abstentions. Errata for TPL-001-5 (agenda item 5) S. Kim provided an overview of the errata background documents. S. Rueckert moved to accept the errata changes to TPL-001-5 to correct a requirement part reference in Requirement R2, Part 2.7. The Committee approved the motion with no objections or abstentions. Drafting Team Nominee Selection Criteria (agenda item 6) S. Bodkin opened the discussion with a background of the topic and the current Drafting Team Nominee Selection Criteria. R. Blohm asked what is considered a Registered Entity. H. Gugel clarified they are considered a Registered Entity under the Registration Criteria of the ROP or the NCR Active Entities List. S. Bodkin shared that a few consultants were not selected for drafting teams in 2019, and this was one of the potential pain points. H. Gugel also shared an example scenario of a drafting team member that has a change of employment, from registered entity to consulting firm. R. Blohm felt that a change of employment should not change their eligibility for the drafting team. He also elaborated on his interpretation of the nominee selection criteria and thought the term ‘subject matter expert’ seemed vague. K. Feliks shared that the Standard Drafting Team Scope document provides some additional guidance on the topic about nominee considerations, and expressed concern about writing a guideline that is overly prescriptive. D. Kiguel felt using the Registered Entity threshold could be problematic for some Canadian entities in the province of Ontario. K. Feliks and C. Yeung advocated for a review of the Standard Drafting Team Scope document to address some of the concerns raised. Legal Update (agenda item 7) L. Perotti provided the legal update regarding recent and upcoming filings. New Business None Adjournment A. Casuscelli thanked the Committee members and observers and adjourned the meeting at 2:58 p.m. Eastern.


Attachment 1 Segment and

Term Representative Organization Proxy Present

(Member or Proxy)

Chair 2020‐21 Amy Casuscelli Sr. Reliability Standards Analyst

Xcel Energy

Yes

Vice Chair 2020‐21 Todd Bennett Managing Director, Reliability Compliance & Audit Services

Associated Electric Cooperative, Inc.

Yes

Segment 1‐2019‐20 Sean Bodkin NERC Compliance Policy Manager

Dominion Resources Services, Inc.

Yes

Segment 1‐2020‐21 John Babik Director, Electric Compliance

JEA Yes

Segment 2‐2019‐20 Charles Yeung Executive Director Interregional Affairs

Southwest Power Pool Yes

Segment 2‐2020‐21 Michael Puscas Compliance Manager

ISO New England, Inc. Yes

Segment 3‐2019‐20 Linn Oelker Manager – Market Compliance

LG&E and KU Services Company

Yes

Segment 3‐2020‐21 Kent Feliks Manager NERC Reliability Assurance – Strategic Initiatives

American Electric Power Company, Inc.

Yes

Segment 4‐2019‐20 Barry Lawson Associate Director, Power Delivery and Reliability

National Rural Electric Cooperative Association

Yes

Segment 4‐2020‐21 Marty Hostler Reliability Compliance Manager

Northern California Power Agency

Yes

Segment 5‐2019‐20 William Winters Chief Engineer, Electrical Engineering

Con Edison Company of New York, Inc.

Yes

Segment 5‐2020‐21 Neil Shockey Principal Manager

Southern California Edison Yes

Standards Committee Attendance – April 22, 2020 2

Segment and Term Representative Organization Proxy Present (Member or Proxy)

Segment 6‐2019‐20 Rebecca Moore Darrah Manager of Reliability Compliance

ACES Power Yes

Segment 6‐2020‐21 Eric Scott Director, Reliability Standards Compliance Oversight

Ameren Services Company Yes

Segment 7‐2019‐20 Venona Greaff Senior Energy Analyst

Occidental Chemical Corporation

Yes

Segment 7‐2020‐21 Vacant N/A

Segment 8‐2019‐20 David Kiguel Independent Yes

Segment 8‐2020‐21 Robert Blohm Managing Director

Keen Resources Ltd. Yes

Segment 9‐2019‐20 Ajinkya Rohankar Advanced Engineer, Division of Energy Regulation and Analysis

Public Service Commission of Wisconsin

Yes

Segment 9‐2020‐21 Vacant N/A

Segment 10‐2019‐20 Steve Rueckert Director of Standards

WECC Yes

Segment 10‐2020‐21 Tony Purgar Manager, Event Analysis & Situational Awareness

ReliabilityFirst Yes

Agenda Item 4 Standards Committee

June 17, 2020

Project 2015-09 Establish and Communicate System Operating Limits Action Authorize initial posting of proposed Reliability Standards IRO-008-3 and TOP-001-6 for a 45-day formal comment period, with ballot pool formed in the first 30 days, and parallel initial ballots and non-binding polls on the Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs), conducted during the last 10 days of the comment period. Background On April 22, 2020, the Standards Committee remanded IRO-008-3 and TOP-001-6 back to the SDT. The SDT was to create consistent use of the term ‘SOL Methodology’ or ‘SOL methodology’ in IRO-008-3, TOP-001-6, and the respective FAC standards as needed. The SDT has made consistent use of ‘SOL methodology’ in the standards. This posting addresses the primary objective of aligning the FAC standards with existing IRO, TOP, and TPL standards, as well as aligning to the new definitions for Operational Planning Analysis and Real-time Assessment that will be effective April 1, 2021, by making modifications to FAC-011, FAC-014, TOP-001, and IRO-008. In addition, modifications were made to several standards in response to the proposed retirement of FAC-010-3. Additionally, a quality review (QR) on the SDT documents was performed March 16 – 27, 2020. NERC Staff included Shamai Elstein, Ed Kichline, and Darrel Richardson. Industry QR members were Dan Custer (MidAmerican Energy), Terry Volmann (Volkmann Consulting, Inc.), Guy Zito (NPCC), Ruth Kloecker (ITC Holdings), and Vic Howell (WECC). The SDT considered all QR inputs and revised the proposed standard where appropriate. Dean LaForest, the SDT chair, approved the final documents before submission to the Standards Committee to request authorization for a 45-day initial comment period and ballot.

Standard IRO-008-3 – Reliability Coordinator Operational Analyses and Real-time Assessments

Draft 1 of IRO-008-3 June 2020 Page 1 of 15

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

Description of Current Draft Completed Actions Date

Standards Committee approved Standard Authorization Request (SAR) for posting

08/19/15

SAR posted for comment 08/20/15 – 09/21/15

Anticipated Actions Date

45-day formal comment period with additional ballot June 2020

10-day final ballot August 2020

NERC Board adoption November 2020

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

Term(s): Text

Agenda Item 4aStandards Committee

June 17, 2020



A. Introduction 1. Title: Reliability Coordinator Operational Analyses and Real-time Assessments

2. Number: IRO-008-3

3. Purpose: Perform analyses and assessments to prevent instability, uncontrolled separation, or Cascading.

4. Applicability

4.1. Reliability Coordinator.

5. Proposed Effective Date:

See Implementation Plan.

6. Background

See Project 2014-03 project page.

B. Requirements and Measures R1. 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 System Operating Limits (SOLs) and Interconnection Operating Reliability Limits (IROLs) within its Wide Area. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M1. Each Reliability Coordinator shall have evidence of a completed Operational Planning Analysis. Such evidence could include but is not limited to dated power flow study results.

R2. Each Reliability Coordinator shall have a coordinated Operating Plan(s) for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of its Operational Planning Analysis as performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing Authorities. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M2. Each Reliability Coordinator shall have evidence that it has a coordinated Operating Plan for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of the Operational Planning Analysis performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing Authorities. Such evidence could include but is not limited to plans for precluding operating in excess of each SOL and IROL that were identified as a result of the Operational Planning Analysis.

http://www.nerc.com/pa/Stand/Pages/Project-2014-03-Revisions-to-TOP-and-IRO-Standards.aspx



R3. Each Reliability Coordinator shall notify impacted entities identified in its Operating Plan(s) cited in Requirement R2 as to their role in such plan(s). [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M3. Each Reliability Coordinator shall have evidence that it notified impacted entities identified in its Operating Plan(s) cited in Requirement R2 as to their role in such plan(s). Such evidence could include, but is not limited to, dated operator logs, or e-mail records.

R4. Each Reliability Coordinator shall ensure that a Real-time Assessment is performed at least once every 30 minutes. [Violation Risk Factor: High] [Time Horizon: Same-day Operations, Real-time Operations]

M4. Each Reliability Coordinator shall have, and make available upon request, evidence to show it ensured that a Real-time Assessment is performed at least once every 30 minutes. This evidence could include but is not limited to dated computer logs showing times the assessment was conducted, dated checklists, or other evidence.

R5. Each Reliability Coordinator shall notify, in accordance with its SOL methodology, 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 System Operating Limit (SOL) exceedance or an Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M5. Each Reliability Coordinator shall make available upon request, evidence that it informed, in accordance with its SOL methodology impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, of its actual or expected operations that result in, or could result in, a System Operating Limit (SOL) exceedance or an Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Reliability Coordinator may provide an attestation.

R6. Each Reliability Coordinator shall notify, in accordance with SOL methodology, impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 has been prevented or mitigated. [Violation Risk Factor: Medium] [Time Horizon: Same-Day Operations, Real-time Operations]



M6. Each Reliability Coordinator shall make available upon request, evidence that it informed, in accordance with its SOL methodology impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 has been prevented or mitigated. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Reliability Coordinator may provide an attestation.

R7. Each Reliability Coordinator shall use its SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. [Violation Risk Factor: Medium ] [Time Horizon: Same-Day Operations, Real-time Operations, Operations Planning]

M7. Each Reliability Coordinator shall have, and provide upon request, evidence that it used its SOL methodology for determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. Evidence could include, but is not limited to: Operating Plans, contingency sets, SOLs, alarming and study reporting thresholds, operator logs, voice recordings or other equivalent evidence.



C. Compliance 1. Compliance Monitoring Process

1.1. Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” (CEA) means NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards.

1.2. Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard.

1.3. Data Retention

The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

Each Reliability Coordinator shall keep data or evidence to show compliance for Requirements R1 through R3, R5, and R6 and Measures M1 through M3, M5, and M6 for a rolling 90-calendar days period for analyses, the most recent 90-calendar days for voice recordings, and 12 months for operating logs and e-mail records unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

Each Reliability Coordinator shall each keep data or evidence for Requirement R4 and Measure M4 for a rolling 30-calendar day period, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

If a Reliability Coordinator is found non-compliant, it shall keep information related to the non-compliance until found compliant or the time period specified above, whichever is longer.

The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records.

1.4. Additional Compliance Information

None



Table of Compliance Elements

R# Time Horizons VRF

Violation Severity Levels

Lower VSL Moderate VSL High VSL Severe VSL

R1 Operations Planning

Medium N/A

N/A N/A The Reliability Coordinator did not perform an Operational Planning Analysis allowing it to assess whether its planned operations for the next-day within its Wide Area will exceed any of its System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs).


Medium N/A N/A N/A The Reliability Coordinator did not have a coordinated Operating Plan(s) for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of its Operational Planning Analysis as performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing Authorities.






For the Requirement R3 and R5 VSLs, the intent of the SDT is to start with the Severe VSL first and then to work your way to the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size. If a Reliability Coordinator has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation


Medium The Reliability Coordinator did not notify one impacted entity or 5% or less of the impacted entities whichever is greater identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify two impacted entities or more than 5% and less than or equal to 10% of the impacted entities whichever is greater, identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify three impacted entities or more than 10% and less than or equal to 15% of the impacted entities whichever is greater, identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify four or more impacted entities or more than 15% of the impacted entities identified in its Operating Plan(s) as to their role in that plan(s).

R4 Same-day Operations, Real-time Operations

High For any sample 24-hour period within the 30-day retention period, the Reliability

For any sample 24-hour period within the 30-day retention period, the Reliability Coordinator’s

For any sample 24-hour period within the 30-day retention period, the Reliability

For any sample 24-hour period within the 30-day retention period, the Reliability Coordinator’s Real-time Assessment was not conducted for three or more 30-minute periods






Coordinator’s Real-time Assessment was not conducted for one 30-minute period within that 24-hour period.

Real-time Assessment was not conducted for two 30-minute periods within that 24-hour period.

Coordinator’s Real-time Assessment was not conducted for three 30-minute periods within that 24-hour period.

within that 24-hour period.

R5 Same-Day Operations, Real-time Operations

High The Reliability Coordinator did not notify, in accordance with its SOL methodology one impacted Transmission Operator or Balancing Authority within its Reliability Coordinator Area or 5% or less of the impacted Transmission Operators and

The Reliability Coordinator did not notify, in accordance with its SOL methodology two impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 5% and less than or equal to 10% of the impacted Transmission

The Reliability Coordinator did not notify, in accordance with its SOL methodology three impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 10% and less than or equal to 15% of

The Reliability Coordinator did not notify, in accordance with its SOL methodology four or more impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 15% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area identified in the Operating Plan(s) as to their role in the plan(s).

OR

The Reliability Coordinator did not notify the other impacted Reliability Coordinators, as indicated in its Operating Plan,






Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area.

Operators and Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area.

the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL)

when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area.






exceedance within its Wide Area.

R6 Same-Day Operations,

Real-time Operations

Medium The Reliability Coordinator did not notify, in accordance with its SOL methodology one impacted Transmission Operator or Balancing Authority within its Reliability Coordinator Area or 5% or less of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator

The Reliability Coordinator did not notify, in accordance with its SOL methodology two impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 5% and less than or equal to 10% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area

The Reliability Coordinator did not notify, in accordance with its SOL methodology three impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 10% and less than or equal to 15% of the impacted Transmission Operators and Balancing Authorities

The Reliability Coordinator did not notify, in accordance with its SOL methodology four or more impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 15% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify four or more other impacted Reliability Coordinators as indicated in its Operating Plan when the System Operating Limit (SOL) exceedance or






Area whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify one other impacted Reliability Coordinator as indicated in its Operating Plan when the when the System

whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R6 was prevented or mitigated.

OR

The Reliability Coordinator did not notify two other impacted Reliability Coordinators as indicated in its Operating Plan when the System Operating Limit (SOL) or

within its Reliability Coordinator Area whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify three other impacted Reliability Coordinators as indicated in its

Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.






Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

Operating Plan when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.



Medium The Reliability Coordinator failed to use its SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis.



D. Regional Variances None

E. Interpretations None

F. Associated Documents Operating Plan - An Operating Plan includes general Operating Processes and specific Operating Procedures. It may be an overview document which provides a prescription for an Operating Plan for the next-day, or it may be a specific plan to address a specific SOL or IROL exceedance identified in the Operational Planning Analysis (OPA). Consistent with the NERC definition, Operating Plans can be general in nature, or they can be specific plans to address specific reliability issues. The use of the term Operating Plan in the revised TOP/IRO standards allows room for both. An Operating Plan references processes and procedures, including electronic data exchange, which are available to the System Operator on a daily basis to allow the operator to reliably address conditions which may arise throughout the day. It is valid for tomorrow, the day after, and the day after that. Operating Plans should be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an OPA or a Real-time Assessment (RTA). As the definition in the Glossary of Terms states, a restoration plan is an example of an Operating Plan. It contains all the overarching principles that the System Operator needs to work his/her way through the restoration process. It is not a specific document written for a specific blackout scenario but rather a collection of tools consisting of processes, procedures, and automated software systems that are available to the operator to use in restoring the system. An Operating Plan can in turn be looked upon in a similar manner. It does not contain a prescription for the specific set-up for tomorrow but contains a treatment of all the processes, procedures, and automated software systems that are at the operator’s disposal. The existence of an Operating Plan, however, does not preclude the need for creating specific action plans for specific SOL or IROL exceedances identified in the OPA. When a Reliability Coordinator performs an OPA, the analysis may reveal instances of possible SOL or IROL exceedances for pre- or post-Contingency conditions. In these instances, Reliability Coordinators are expected to ensure that there are plans in place to prevent or mitigate those SOLs or IROLs, should those operating conditions be encountered the next day. The Operating Plan may contain a description of the process by which specific prevention or mitigation plans for day-to-day SOL or IROL exceedances identified in the OPA are handled and communicated. This approach could alleviate any potential administrative burden associated with perceived requirements for continual day-to-day updating of “the Operating Plan document” for compliance purposes.



Version History

Version Date Action Change Tracking

1 October 17, 2008

Adopted by NERC Board of Trustees

1 March 17, 2011

Order issued by FERC approving IRO-008-1 (approval effective 5/23/11)

1 February 28, 2014

Updated VSLs and VRF’s based on June 24, 2013 approval.

2 November 13, 2014

Adopted by NERC Board of Trustees Revisions under Project 2014-03

2 November 19, 2015

FERC approved IRO-008-2. Docket No. RM15-16-000. Order No. 817

3 TBD Adopted by NERC Board of Trustees Revisions under Project 2015-09



Note: The Guidelines and Technical Basis section has not been revised as part of Project 2019-02. A separate technical rationale document has been created to cover Project 2019-02 revisions. Future edits to this section will be conducted through the Technical Rationale for Reliability Standards Project and the Standards Drafting Process.



Description of Current Draft Completed Actions Date


08/19/15



45-day formal comment period with additional ballot June 2020




Term(s): Text

Agenda Item 4b Standards Committee

June 17, 2020Standard IRO-008-23 – Reliability Coordinator Operational Analyses and Real-time Assessments



A. Introduction 1. Title: Reliability Coordinator Operational Analyses and Real-time Assessments

2. Number: IRO-008-23

3. Purpose: Perform analyses and assessments to prevent instability, uncontrolled separation, or Cascading.

4. Applicability

4.1. Reliability Coordinator.

5. Proposed Effective Date:

See Implementation Plan.

6. Background

See Project 2014-03 project page.

B. Requirements and Measures R1. 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 System Operating Limits (SOLs) and Interconnection Operating Reliability Limits (IROLs) within its Wide Area. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M1. Each Reliability Coordinator shall have evidence of a completed Operational Planning Analysis. Such evidence could include but is not limited to dated power flow study results.

R2. Each Reliability Coordinator shall have a coordinated Operating Plan(s) for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of its Operational Planning Analysis as performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing Authorities. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M2. Each Reliability Coordinator shall have evidence that it has a coordinated Operating Plan for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of the Operational Planning Analysis performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing Authorities. Such evidence could include but is not limited to plans for precluding operating in excess of each SOL and IROL that were identified as a result of the Operational Planning Analysis.

http://www.nerc.com/pa/Stand/Pages/Project-2014-03-Revisions-to-TOP-and-IRO-Standards.aspx



R3. Each Reliability Coordinator shall notify impacted entities identified in its Operating Plan(s) cited in Requirement R2 as to their role in such plan(s). [Violation Risk Factor: Medium] [Time Horizon: Operations Planning]

M3. Each Reliability Coordinator shall have evidence that it notified impacted entities identified in its Operating Plan(s) cited in Requirement R2 as to their role in such plan(s). Such evidence could include, but is not limited to, dated operator logs, or e-mail records.

R4. Each Reliability Coordinator shall ensure that a Real-time Assessment is performed at least once every 30 minutes. [Violation Risk Factor: High] [Time Horizon: Same-day Operations, Real-time Operations]

M4. Each Reliability Coordinator shall have, and make available upon request, evidence to show it ensured that a Real-time Assessment is performed at least once every 30 minutes. This evidence could include but is not limited to dated computer logs showing times the assessment was conducted, dated checklists, or other evidence.

R5. Each Reliability Coordinator shall notify, in accordance with its SOL methodology, 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 System Operating Limit (SOL) exceedance or an Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M5. Each Reliability Coordinator shall make available upon request, evidence that it informed, in accordance with its SOL methodology impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, of its actual or expected operations that result in, or could result in, a System Operating Limit (SOL) exceedance or an Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Reliability Coordinator may provide an attestation.

R6. Each Reliability Coordinator shall notify, in accordance with SOL methodology, impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 has been prevented or mitigated. [Violation Risk Factor: Medium] [Time Horizon: Same-Day Operations, Real-time Operations]



M6. Each Reliability Coordinator shall make available upon request, evidence that it informed, in accordance with its SOL methodology impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area, and other impacted Reliability Coordinators as indicated in its Operating Plan, when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 has been prevented or mitigated. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Reliability Coordinator may provide an attestation.

R7. Each Reliability Coordinator shall use its SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. [Violation Risk Factor: Medium ] [Time Horizon: Same-Day Operations, Real-time Operations, Operations Planning]

M7. Each Reliability Coordinator shall have, and provide upon request, evidence that it used its SOL methodology for determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. Evidence could include, but is not limited to: Operating Plans, contingency sets, SOLs, alarming and study reporting thresholds, operator logs, voice recordings or other equivalent evidence.




1.1. Compliance Enforcement Authority

As defined in the NERC Rules of Procedure, “Compliance Enforcement Authority” (CEA) means NERC or the Regional Entity in their respective roles of monitoring and enforcing compliance with the NERC Reliability Standards.

1.2. Compliance Monitoring and Assessment Processes

As defined in the NERC Rules of Procedure, “Compliance Monitoring and Assessment Processes” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated reliability standard.

1.3. Data Retention

The following evidence retention periods identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full time period since the last audit.

Each Reliability Coordinator shall keep data or evidence to show compliance for Requirements R1 through R3, R5, and R6 and Measures M1 through M3, M5, and M6 for a rolling 90-calendar days period for analyses, the most recent 90-calendar days for voice recordings, and 12 months for operating logs and e-mail records unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

Each Reliability Coordinator shall each keep data or evidence for Requirement R4 and Measure M4 for a rolling 30-calendar day period, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

If a Reliability Coordinator is found non-compliant, it shall keep information related to the non-compliance until found compliant or the time period specified above, whichever is longer.

The Compliance Enforcement Authority shall keep the last audit records and all requested and submitted subsequent audit records.

1.4. Additional Compliance Information

None



Table of Compliance Elements





Medium N/A

N/A N/A The Reliability Coordinator did not perform an Operational Planning Analysis allowing it to assess whether its planned operations for the next-day within its Wide Area will exceed any of its System Operating Limits (SOLs) and Interconnection Reliability Operating Reliability Limits (IROLs).


Medium N/A N/A N/A The Reliability Coordinator did not have a coordinated Operating Plan(s) for next-day operations to address potential System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances identified as a result of its Operational Planning Analysis as performed in Requirement R1 while considering the Operating Plans for the next-day provided by its Transmission Operators and Balancing






Authorities.

For the Requirement R3 and R5 VSLs, the intent of the SDT is to start with the Severe VSL first and then to work your way to the left until you find the situation that fits. In this manner, the VSL will not be discriminatory by size. If a Reliability Coordinator has just one affected reliability entity to inform, the intent is that that situation would be a Severe violation


Medium The Reliability Coordinator did not notify one impacted entity or 5% or less of the impacted entities whichever is greater identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify two impacted entities or more than 5% and less than or equal to 10% of the impacted entities whichever is greater, identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify three impacted entities or more than 10% and less than or equal to 15% of the impacted entities whichever is greater, identified in its Operating Plan(s) as to their role in that plan(s).

The Reliability Coordinator did not notify four or more impacted entities or more than 15% of the impacted entities identified in its Operating Plan(s) as to their role in that plan(s).

R4 Same-day Operations, Real-time

High For any sample 24-hour period within the 30-day retention

For any sample 24-hour period within the 30-day retention period,

For any sample 24-hour period within the 30-day retention

For any sample 24-hour period within the 30-day retention period, the Reliability Coordinator’s Real-time






Operations period, the Reliability Coordinator’s Real-time Assessment was not conducted for one 30-minute period within that 24-hour period.

the Reliability Coordinator’s Real-time Assessment was not conducted for two 30-minute periods within that 24-hour period.

period, the Reliability Coordinator’s Real-time Assessment was not conducted for three 30-minute periods within that 24-hour period.

Assessment was not conducted for three or more 30-minute periods within that 24-hour period.

R5 Same-Day Operations, Real-time Operations

High The Reliability Coordinator did not notify, in accordance with its SOL methodology one impacted Transmission Operator or Balancing Authority within its Reliability Coordinator Area or 5% or less of the impacted

The Reliability Coordinator did not notify, in accordance with its SOL methodology two impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 5% and less than or equal to 10% of

The Reliability Coordinator did not notify, in accordance with its SOL methodology three impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 10% and

The Reliability Coordinator did not notify ,notify, in accordance with its SOL methodology four or more impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area or more than 15% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area identified in the Operating Plan(s) as to their role in the plan(s).

OR

The Reliability Coordinator did not notify the other impacted






Transmission Operators and Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance

the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area.

less than or equal to 15% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability

Reliability Coordinators, as indicated in its Operating Plan, when the results of its Real-time Assessment indicate an actual or expected condition that results in, or could result in, a System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance within its Wide Area.






within its Wide Area.

Operating Limit (IROL) exceedance within its Wide Area.



Medium The Reliability Coordinator did not notify, in accordance with its SOL methodology one impacted Transmission Operator or Balancing Authority within its Reliability Coordinator Area or 5% or less of the impacted Transmission Operators and Balancing Authorities within its

The Reliability Coordinator did not notify, in accordance with its SOL methodology two impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 5% and less than or equal to 10% of the impacted Transmission Operators and Balancing Authorities within

The Reliability Coordinator did not notify, in accordance with its SOL methodology three impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 10% and less than or equal to 15% of the impacted Transmission Operators and

The Reliability Coordinator did not notify ,notify, in accordance with its SOL methodology four or more impacted Transmission Operators or Balancing Authorities within its Reliability Coordinator Area or more than 15% of the impacted Transmission Operators and Balancing Authorities within its Reliability Coordinator Area when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify four or more other impacted Reliability Coordinators as indicated in its Operating Plan






Reliability Coordinator Area whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify one other impacted Reliability Coordinator as indicated in its Operating Plan

its Reliability Coordinator Area whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R6 was prevented or mitigated.

OR

The Reliability Coordinator did not notify two other impacted Reliability Coordinators as indicated in its Operating Plan when the System

Balancing Authorities within its Reliability Coordinator Area whichever is greater, when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

OR

The Reliability Coordinator did not notify three other impacted Reliability

when the System Operating Limit (SOL) exceedance or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.






when the when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.

Coordinators as indicated in its Operating Plan when the System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) exceedance identified in Requirement R5 was prevented or mitigated.



Medium The Reliability Coordinator failed to use its SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis.



D. Regional Variances None

E. Interpretations None

F. Associated Documents Operating Plan - An Operating Plan includes general Operating Processes and specific Operating Procedures. It may be an overview document which provides a prescription for an Operating Plan for the next-day, or it may be a specific plan to address a specific SOL or IROL exceedance identified in the Operational Planning Analysis (OPA). Consistent with the NERC definition, Operating Plans can be general in nature, or they can be specific plans to address specific reliability issues. The use of the term Operating Plan in the revised TOP/IRO standards allows room for both. An Operating Plan references processes and procedures, including electronic data exchange, which are available to the System Operator on a daily basis to allow the operator to reliably address conditions which may arise throughout the day. It is valid for tomorrow, the day after, and the day after that. Operating Plans should be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an OPA or a Real-time Assessment (RTA). As the definition in the Glossary of Terms states, a restoration plan is an example of an Operating Plan. It contains all the overarching principles that the System Operator needs to work his/her way through the restoration process. It is not a specific document written for a specific blackout scenario but rather a collection of tools consisting of processes, procedures, and automated software systems that are available to the operator to use in restoring the system. An Operating Plan can in turn be looked upon in a similar manner. It does not contain a prescription for the specific set-up for tomorrow but contains a treatment of all the processes, procedures, and automated software systems that are at the operator’s disposal. The existence of an Operating Plan, however, does not preclude the need for creating specific action plans for specific SOL or IROL exceedances identified in the OPA. When a Reliability Coordinator performs an OPA, the analysis may reveal instances of possible SOL or IROL exceedances for pre- or post-Contingency conditions. In these instances, Reliability Coordinators are expected to ensure that there are plans in place to prevent or mitigate those SOLs or IROLs, should those operating conditions be encountered the next day. The Operating Plan may contain a description of the process by which specific prevention or mitigation plans for day-to-day SOL or IROL exceedances identified in the OPA are handled and communicated. This approach could alleviate any potential administrative burden associated with perceived requirements for continual day-to-day updating of “the Operating Plan document” for compliance purposes.



Version History

Version Date Action Change Tracking

1 October 17, 2008

Adopted by NERC Board of Trustees

1 March 17, 2011

Order issued by FERC approving IRO-008-1 (approval effective 5/23/11)

1 February 28, 2014

Updated VSLs and VRF’s based on June 24, 2013 approval.

2 November 13, 2014

Adopted by NERC Board of Trustees Revisions under Project 2014-03

2 November 19, 2015

FERC approved IRO-008-2. Docket No. RM15-16-000. Order No. 817

3 TBD Adopted by NERC Board of Trustees Revisions under Project 2015-09



Note: The Guidelines and Technical Basis section has not been revised as part of Project 2019-02. A separate technical rationale document has been created to cover Project 2019-02 revisions. Future edits to this section will be conducted through the Technical Rationale for Reliability Standards Project and the Standards Drafting Process.

Guidelines and Technical Basis

Rationale:

During development of this standard, text boxes were embedded within the standard to explain the rationale for various parts of the standard. Upon BOT approval, the text from the rationale text boxes was moved to this section.

Changes made to the proposed definitions were made in order to respond to issues raised in NOPR paragraphs 55, 73, and 74 dealing with analysis of SOLs in all time horizons, questions on Protection Systems and Special Protection Systems in NOPR paragraph 78, and recommendations on phase angles from the SW Outage Report (recommendation 27). The intent of such changes is to ensure that Real-time Assessments contain sufficient details to result in an appropriate level of situational awareness. Some examples include: 1) analyzing phase angles which may result in the implementation of an Operating Plan to adjust generation or curtail transactions so that a Transmission facility may be returned to service, or 2) evaluating the impact of a modified Contingency resulting from the status change of a Special Protection Scheme from enabled/in-service to disabled/out-of-service.

Rationale for R1: Revised in response to NOPR paragraph 96 on the obligation of Reliability Coordinators to monitor SOLs. Measure M1 revised for consistency with TOP-003-3, Measure M1.

Rationale for R2 and R3: Requirements added in response to IERP and SW Outage Report recommendations concerning the coordination and review of plans.

Rationale for R5 and R6: In Requirements R5 and R6 the use of the term ‘impacted’ and the tie to the Operating Plan where notification protocols will be set out should minimize the volume of notifications.

TOP-001-6 - Transmission Operations

Draft 1 of TOP-001-6 June 2020 Page 1 of 27


Description of Current Draft

Completed Actions Date


08/19/15


45-day formal comment period with initial ballot 08/27/18 - 10/17/18


45-day formal comment period with initial ballot June 2020




Term(s): None

Agenda Item 4cStandards Committee

June 17, 2020



A. IntroductionTitle: Transmission Operations

Number: TOP-001-6

Purpose: To prevent instability, uncontrolled separation, or Cascading outages that adversely impact the reliability of the Interconnection by ensuring prompt action to prevent or mitigate such occurrences.

Applicability:

1.1. Functional Entities:

4.1.1. Balancing Authority

4.1.2. Transmission Operator

4.1.3. Generator Operator

4.1.4. Distribution Provider

Effective Date: See Implementation Plan



B. Requirements and Measures R1. Each Transmission Operator shall act to maintain the reliability of its Transmission

Operator Area via its own actions or by issuing Operating Instructions. [Violation Risk Factor: High][Time Horizon: Same-Day Operations, Real-time Operations]

M1. Each Transmission Operator shall have and provide evidence which may include but is not limited to dated operator logs, dated records, dated and time-stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent documentation, that will be used to determine that it acted to maintain the reliability of its Transmission Operator Area via its own actions or by issuing Operating Instructions.

R2. Each Balancing Authority shall act to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions. [Violation Risk Factor: High][Time Horizon: Same-Day Operations, Real-time Operations]

M2. Each Balancing Authority shall have and provide evidence which may include but is not limited to dated operator logs, dated records, dated and time-stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent documentation, that will be used to determine that it acted to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions.

R3. Each Balancing Authority, Generator Operator, and Distribution Provider shall comply with each Operating Instruction issued by its Transmission Operator(s), unless such action cannot be physically implemented or it would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M3. Each Balancing Authority, Generator Operator, and Distribution Provider shall make available upon request, evidence that it complied with each Operating Instruction issued by the Transmission Operator(s) unless such action could not be physically implemented or it would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. In such cases, the Balancing Authority, Generator Operator, and Distribution Provider shall have and provide copies of the safety, equipment, regulatory, or statutory requirements as evidence for not complying with the Transmission Operator’s Operating Instruction. If such a situation has not occurred, the Balancing Authority, Generator Operator, or Distribution Provider may provide an attestation.

R4. Each Balancing Authority, Generator Operator, and Distribution Provider shall inform its Transmission Operator of its inability to comply with an Operating Instruction issued by its Transmission Operator. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]



M4. Each Balancing Authority, Generator Operator, and Distribution Provider shall make available upon request, evidence which may include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent evidence in electronic or hard copy format, that it informed its Transmission Operator of its inability to comply with its Operating Instruction issued. If such a situation has not occurred, the Balancing Authority, Generator Operator, or Distribution Provider may provide an attestation.

R5. Each Transmission Operator, Generator Operator, and Distribution Provider shall comply with each Operating Instruction issued by its Balancing Authority, unless such action cannot be physically implemented or it would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M5. Each Transmission Operator, Generator Operator, and Distribution Provider shall make available upon request, evidence that it complied with each Operating Instruction issued by its Balancing Authority unless such action could not be physically implemented or it would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. In such cases, the Transmission Operator, Generator Operator, and Distribution Provider shall have and provide copies of the safety, equipment, regulatory, or statutory requirements as evidence for not complying with the Balancing Authority’s Operating Instruction. If such a situation has not occurred, the Transmission Operator, Generator Operator, or Distribution Provider may provide an attestation.

R6. Each Transmission Operator, Generator Operator, and Distribution Provider shall inform its Balancing Authority of its inability to comply with an Operating Instruction issued by its Balancing Authority. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M6. Each Transmission Operator, Generator Operator, and Distribution Provider shall make available upon request, evidence which may include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent evidence in electronic or hard copy format, that it informed its Balancing Authority of its inability to comply with its Operating Instruction. If such a situation has not occurred, the Transmission Operator, Generator Operator, or Distribution Provider may provide an attestation.

R7. Each Transmission Operator shall 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 such assistance cannot be physically implemented or would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]



M7. Each Transmission Operator shall make available upon request, evidence that comparable requested assistance, if able, was provided to other Transmission Operators within its Reliability Coordinator Area unless such assistance could not be physically implemented or would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. If no request for assistance was received, the Transmission Operator may provide an attestation.

R8. Each Transmission Operator shall 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. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-Time Operations]

M8. Each Transmission Operator shall make available upon request, evidence that it informed 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. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If no such situations have occurred, the Transmission Operator may provide an attestation.

R9. Each Balancing Authority and Transmission Operator shall 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 between the affected entities. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same-Day Operations, Real-Time Operations]

M9. Each Balancing Authority and Transmission Operator shall make available upon request, evidence that it notified 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. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Balancing Authority or Transmission Operator may provide an attestation.

R10. Each Transmission Operator shall perform the following for determining System Operating Limit (SOL) exceedances within its Transmission Operator Area: [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

10.1. Monitor Facilities within its Transmission Operator Area;



10.2. Monitor the status of Remedial Action Schemes within its Transmission Operator Area;

10.3. Monitor non-BES facilities within its Transmission Operator Area identified as necessary by the Transmission Operator;

10.4. Obtain and utilize status, voltages, and flow data for Facilities outside its Transmission Operator Area identified as necessary by the Transmission Operator;

10.5. Obtain and utilize the status of Remedial Action Schemes outside its Transmission Operator Area identified as necessary by the Transmission Operator; and

10.6. Obtain and utilize status, voltages, and flow data for non-BES facilities outside its Transmission Operator Area identified as necessary by the Transmission Operator.

M10. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to Energy Management System description documents, computer printouts, Supervisory Control and Data Acquisition (SCADA) data collection, or other equivalent evidence that will be used to confirm that it monitored or obtained and utilized data as required to determine any System Operating Limit (SOL) exceedances within its Transmission Operator Area.

R11. Each Balancing Authority shall monitor its Balancing Authority Area, including the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency. [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

M11. Each Balancing Authority shall have, and provide upon request, evidence that could include but is not limited to Energy Management System description documents, computer printouts, SCADA data collection, or other equivalent evidence that will be used to confirm that it monitors its Balancing Authority Area, including the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

R12. Each Transmission Operator shall not operate outside any identified Interconnection Reliability Operating Limit (IROL) for a continuous duration exceeding its associated IROL Tv. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M12. Each Transmission Operator shall make available evidence to show that for any occasion in which it operated outside any identified Interconnection Reliability Operating Limit (IROL), the continuous duration did not exceed its associated IROL Tv. Such evidence could include but is not limited to dated computer logs or reports in electronic or hard copy format specifying the date, time, duration, and details of the



excursion. If such a situation has not occurred, the Transmission Operator may provide an attestation that an event has not occurred.

R13. Each Transmission Operator shall ensure that a Real-time Assessment is performed at least once every 30 minutes. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M13. Each Transmission Operator shall have, and make available upon request, evidence to show it ensured that a Real-Time Assessment was performed at least once every 30 minutes. This evidence could include but is not limited to dated computer logs showing times the assessment was conducted, dated checklists, or other evidence.

R14. Each Transmission Operator shall initiate its Operating Plan to mitigate a SOL exceedance identified as part of its Real-time monitoring or Real-time Assessment. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M14. Each Transmission Operator shall have evidence that it initiated its Operating Plan for mitigating SOL exceedances identified as part of its Real-time monitoring or Real-time Assessments. This evidence could include but is not limited to dated computer logs showing times the Operating Plan was initiated, dated checklists, or other evidence. Other evidence could include but is not limited to: Reliability Coordinator’s SOL methodology, system logs/records showing successfully mitigated SOL exceedances in conjunction with Operating Plans (e.g. mutually agreed operating protocols between TOPs and their Reliability Coordinator, Operating Procedures, Operating Processes, operating policies, generator redispatch logs, equipment settings for automatically switched equipment and reactive power/voltage control devices, switching schedules, etc.).

R15. Each Transmission Operator shall inform its Reliability Coordinator of actions taken to return the System to within limits when a SOL has been exceeded in accordance with its Reliability Coordinator’s SOL methodology. [Violation Risk Factor: Medium] [Time Horizon: Real-Time Operations]

M15. Each Transmission Operator shall make available evidence that it informed its Reliability Coordinator of actions taken to return the System to within limits when a SOL was exceeded in accordance with its Reliability Coordinator’s SOL methodology. Such evidence could include but is not limited to dated operator logs, electronic communications, voice recordings or transcripts of voice recordings, or dated computer printouts. If such a situation has not occurred, the Transmission Operator may provide an attestation.

R16. Each Transmission Operator shall provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]



M16. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to a documented procedure or equivalent evidence that will be used to confirm that the Transmission Operator has provided its System Operators with the authority to approve planned outages and maintenance of telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R17. Each Balancing Authority shall provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]

M17. Each Balancing Authority shall have, and provide upon request, evidence that could include but is not limited to a documented procedure or equivalent evidence that will be used to confirm that the Balancing Authority has provided its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R18. Each Transmission Operator shall operate to the most limiting parameter in instances where there is a difference in SOLs. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]

M18. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to operator logs, voice recordings, electronic communications, or equivalent evidence that will be used to determine if it operated to the most limiting parameter in instances where there is a difference in SOLs.

R19. Reserved.

M19. Reserved.

R20. Each Transmission Operator shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from in order for it to perform its Real-time monitoring and Real-time Assessments. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M20. Each Transmission Operator shall have, and provide upon request, evidence that could include, but is not limited to, system specifications, system diagrams, or other documentation that lists its data exchange capabilities, including redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from



in order to perform its Real-time monitoring and Real-time Assessments as specified in the requirement.

R21. Each Transmission Operator shall test its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality at least once every 90 calendar days. If the test is unsuccessful, the Transmission Operator shall initiate action within two hours to restore redundant functionality. [Violation Risk Factor: Medium ] [Time Horizon: Operations Planning]

M21. Each Transmission Operator shall have, and provide upon request, evidence that it tested its primary Control Center data exchange capabilities specified in Requirement R20 for the redundant functionality, or experienced an event that demonstrated the redundant functionality; and, if the test was unsuccessful, initiated action within two hours to restore redundant functionality as specified in Requirement R21. Evidence could include, but is not limited to: dated and time-stamped test records, operator logs, voice recordings, or electronic communications.

R22. Reserved.

M22. Reserved.

R23. Each Balancing Authority shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the Balancing Authority's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Transmission Operator, and the entities it has identified it needs data from in order for it to perform its Real-time monitoring and analysis functions. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M23. Each Balancing Authority shall have, and provide upon request, evidence that could include, but is not limited to, system specifications, system diagrams, or other documentation that lists its data exchange capabilities, including redundant and diversely routed data exchange infrastructure within the Balancing Authority's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Transmission Operator, and the entities it has identified it needs data from in order to perform its Real-time monitoring and analysis functions as specified in the requirement.

R24. Each Balancing Authority shall test its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality at least once every 90 calendar days. If the test is unsuccessful, the Balancing Authority shall initiate action within two hours to restore redundant functionality. [Violation Risk Factor: Medium ] [Time Horizon: Operations Planning]

M24. Each Balancing Authority shall have, and provide upon request, evidence that it tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, or experienced an event that demonstrated the redundant functionality; and, if the test was unsuccessful, initiated action within two



hours to restore redundant functionality as specified in Requirement R24. Evidence could include, but is not limited to: dated and time-stamped test records, operator logs, voice recordings, or electronic communications.

R25. Each Transmission Operator shall use the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. [Violation Risk Factor: High ] [Time Horizon: Same-Day Operations, Real-time Operations, Operations Planning]

M25. Each Transmission Operator shall have, and provide upon request, evidence that it used the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. Evidence could include, but is not limited to: Reliability Coordinator’s SOL methodology, Operating Plans, contingency sets, alarming and study reporting thresholds, operator logs, voice recordings or other equivalent evidence.




1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means NERC or the Regional Entity, or any entity as otherwise designated by an Applicable Governmental Authority, in their respective roles of monitoring and/or enforcing compliance with mandatory and enforceable Reliability Standards in their respective jurisdictions.

1.2. Evidence Retention: The following evidence retention period(s) identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full-time period since the last audit.

The applicable entity shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider shall each keep data or evidence for each applicable Requirement R1 through R11, and Measure M1 through M11, for the current calendar year and one previous calendar year, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Transmission Operator shall retain evidence for three calendar years of any occasion in which it has exceeded an identified IROL and its associated IROL Tv as specified in Requirement R12 and Measure M12.

• Each Transmission Operator shall keep data or evidence for Requirement R13 and Measure M13 for a rolling 30-day period, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Transmission Operator shall retain evidence and that it initiated its Operating Plan to mitigate a SOL exceedance as specified in Requirement R14 and Measurement M14 for rolling 12 months.

• Each Transmission Operator and Balancing Authority shall each keep data or evidence for each applicable Requirement R15 through R18, and Measure M15 through M18 for the current calendar year and one



previous calendar year, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Transmission Operator shall keep data or evidence for Requirement R20 and Measure M20 for the current calendar year and one previous calendar year.

• Each Transmission Operator shall keep evidence for Requirement R21 and Measure M21 for the most recent twelve calendar months, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Balancing Authority shall keep data or evidence for Requirement R23 and Measure M23 for the current calendar year and one previous calendar year.

• Each Balancing Authority shall keep evidence for Requirement R24 and Measure M24 for the most recent twelve calendar months, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Transmission Operator shall retain evidence that it used the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis as specified in Requirement R25 and Measurement M25 for a rolling 12 months.

1.3. Compliance Monitoring and Enforcement Program As defined in the NERC Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated Reliability Standard.




R # Violation Severity Levels


R1. N/A N/A N/A The Transmission Operator failed to act to maintain the reliability of its Transmission Operator Area via its own actions or by issuing Operating Instructions.

R2. N/A N/A N/A The Balancing Authority failed to act to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions.

R3. N/A N/A N/A

The responsible entity did not comply with an Operating Instruction issued by the Transmission Operator, and such action could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R4. N/A N/A N/A The responsible entity did not inform its Transmission Operator of its inability to





comply with an Operating Instruction issued by its Transmission Operator.

R5. N/A N/A N/A The responsible entity did not comply with an Operating Instruction issued by the Balancing Authority, and such action could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R6. N/A N/A N/A The responsible entity did not inform its Balancing Authority of its inability to comply with an Operating Instruction issued by its Balancing Authority.

R7. N/A N/A N/A

The Transmission Operator did not provide comparable assistance to other Transmission Operators within its Reliability Coordinator Area, when requested and able, and the





requesting entity had implemented its Emergency procedures, and such actions could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R8. The Transmission Operator did not inform one known impacted Transmission Operator or 5% or less of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform one known impacted

The Transmission Operator did not inform two known impacted Transmission Operators or more than 5% and less than or equal to 10% of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform two known impacted Balancing

The Transmission Operator did not inform three known impacted Transmission Operators or more than 10% and less than or equal to 15% of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform three known impacted Balancing

The Transmission Operator did not inform its Reliability Coordinator of its actual or expected operations that resulted in, or could have resulted in, an Emergency on those respective Transmission Operator Areas. OR The Transmission Operator did not inform four or more known impacted Transmission Operators or more than 15% of the known impacted Transmission Operators of its actual or expected





Balancing Authorities or 5% or less of the known impacted Balancing Authorities, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Balancing Authority Areas.

Authorities or more than 5% and less than or equal to 10% of the known impacted Balancing Authorities, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Balancing Authority Areas.


operations that resulted in, or could have resulted in, an Emergency on those respective Transmission Operator Areas. OR, The Transmission Operator did not inform four or more known impacted Balancing Authorities or more than 15% of the known impacted Balancing Authorities of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Balancing Authority Areas.

R9. The responsible entity did not notify one known impacted interconnected entity or 5% or less of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control

The responsible entity did not notify two known impacted interconnected entities or more than 5% and less than or equal to 10% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30

The responsible entity did not notify three known impacted interconnected entities or more than 10% and less than or equal to 15% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30

The responsible entity did not notify its Reliability Coordinator of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.





equipment, monitoring and assessment capabilities, or associated communication channels between the affected entities.

minutes or more, for telemetering and control equipment, monitoring and assessment capabilities, or associated communication channels between the affected entities.


OR, The responsible entity did not notify four or more known impacted interconnected entities or more than 15% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control equipment, monitoring and assessment capabilities, or associated communication channels between the affected entities.

R10. The Transmission Operator did not monitor, obtain, or utilize one of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize two of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize three of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize four or more of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10 Part 10.1 through 10.6.





R11. N/A N/A The Balancing Authority did not monitor the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

The Balancing Authority did not monitor its Balancing Authority Area, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

R12. N/A N/A N/A The Transmission Operator exceeded an identified Interconnection Reliability Operating Limit (IROL) for a continuous duration greater than its associated IROL Tv.

R13. For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for one 30-minute period within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for two 30-minute periods within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for three 30-minute periods within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for four or more 30-minute periods within that 24-hour period.

R14. N/A N/A N/A The Transmission Operator did not initiate its Operating





Plan for mitigating a SOL exceedance identified as part of its Real-time monitoring or Real-time Assessment

R15. N/A N/A N/A The Transmission Operator did not inform in accordance with its Reliability Coordinator’s SOL methodology its Reliability Coordinator of actions taken to return the System to within limits when a SOL had been exceeded.

R16. N/A N/A N/A The Transmission Operator did not provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.





R17. N/A N/A N/A The Balancing Authority did not provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R18. N/A N/A N/A The Transmission Operator failed to operate to the most limiting parameter in instances where there was a difference in SOLs.

R19. Reserved.

R20. N/A N/A The Transmission Operator had data exchange capabilities with its Reliability Coordinator, Balancing Authority, and identified entities for performing Real-time

The Transmission Operator did not have data exchange capabilities with its Reliability Coordinator, Balancing Authority, and identified entities for performing Real-time





monitoring and Real-time Assessments, but did not have redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, as specified in the Requirement.

monitoring and Real-time Assessments as specified in the Requirement.

R21. The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality, but did so more than 90 calendar days but less than or equal to 120 calendar days since the previous test; OR The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement

The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality, but did so more than 120 calendar days but less than or equal to 150 calendar days since the previous test; OR The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality at least once every 90 calendar


The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality, but did so more than 180 calendar days since the previous test;

OR

The Transmission Operator did not test its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality;





R20 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, initiated action to restore the redundant functionality in more than 2 hours and less than or equal to 4 hours.

days but, following an unsuccessful test, initiated action to restore the redundant functionality in more than 4 hours and less than or equal to 6 hours.


OR The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, did not initiate action within 8 hours to restore the redundant functionality.

R22. Reserved.

R23. N/A N/A The Balancing Authority had data exchange capabilities with its Reliability Coordinator, Transmission Operator, and identified entities for performing Real-time monitoring and analysis functions, but did not have redundant and diversely routed data exchange infrastructure

The Balancing Authority did not have data exchange capabilities with its Reliability Coordinator, Transmission Operator, and identified entities for performing Real-time monitoring and analysis functions as specified in the Requirement.





within the Balancing Authority's primary Control Center, as specified in the Requirement.

R24. The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, but did so more than 90 calendar days but less than or equal to 120 calendar days since the previous test; OR The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, initiated action to restore the redundant

The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, but did so more than 120 calendar days but less than or equal to 150 calendar days since the previous test; OR The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, initiated action to restore the redundant functionality in


The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, but did so more than 180 calendar days since the previous test;

OR

The Balancing Authority did not test its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality;

OR The Balancing Authority tested its primary Control Center data exchange capabilities specified in





functionality in more than 2 hours and less than or equal to 4 hours.

more than 4 hours and less than or equal to 6 hours.


Requirement R23 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, did not initiate action within 8 hours to restore the redundant functionality.

R25. The Transmission Operator failed to use the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis.



D. Regional Variances None.

E. Associated Documents The Project 2014-03 SDT has created the SOL Exceedance White Paper as guidance on SOL issues and the URL for that document is: http://www.nerc.com/pa/stand/Pages/TOP0013RI.aspx. Operating Plan - An Operating Plan includes general Operating Processes and specific Operating Procedures. It may be an overview document which provides a prescription for an Operating Plan for the next-day, or it may be a specific plan to address a specific SOL or IROL exceedance identified in the Operational Planning Analysis (OPA). Consistent with the NERC definition, Operating Plans can be general in nature, or they can be specific plans to address specific reliability issues. The use of the term Operating Plan in the revised TOP/IRO standards allows room for both. An Operating Plan references processes and procedures, including electronic data exchange, which are available to the System Operator on a daily basis to allow the operator to reliably address conditions which may arise throughout the day. It is valid for tomorrow, the day after, and the day after that. Operating Plans should be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an OPA or a Real-time Assessment (RTA). As the definition in the Glossary of Terms states, a restoration plan is an example of an Operating Plan. It contains all the overarching principles that the System Operator needs to work his/her way through the restoration process. It is not a specific document written for a specific blackout scenario but rather a collection of tools consisting of processes, procedures, and automated software systems that are available to the operator to use in restoring the system. An Operating Plan can in turn be looked upon in a similar manner. It does not contain a prescription for the specific set-up for tomorrow but contains a treatment of all the processes, procedures, and automated software systems that are at the operator’s disposal. The existence of an Operating Plan, however, does not preclude the need for creating specific action plans for specific SOL or IROL exceedances identified in the OPA. When a Reliability Coordinator performs an OPA, the analysis may reveal instances of possible SOL or IROL exceedances for pre- or post-Contingency conditions. In these instances, Reliability Coordinators are expected to ensure that there are plans in place to prevent or mitigate those SOLs or IROLs, should those operating conditions be encountered the next day. The Operating Plan may contain a description of the process by which specific prevention or mitigation plans for day-to-day SOL or IROL exceedances identified in the OPA are handled and communicated. This approach could alleviate any potential administrative burden associated with perceived requirements for continual day-to-day updating of “the Operating Plan document” for compliance purposes.

http://www.nerc.com/pa/stand/Pages/TOP0013RI.aspx



Version History Version Date Action Change Tracking

0 April 1, 2005 Effective Date New

0 August 8, 2005 Removed “Proposed” from Effective Date

Errata

1 November 1, 2006

Adopted by Board of Trustees Revised

1a May 12, 2010 Added Appendix 1 – Interpretation of R8 approved by Board of Trustees on May 12, 2010

Interpretation

1a September 15, 2011

FERC Order issued approved the Interpretation of R8 (FERC Order became effective November 21, 2011)

Interpretation

2 May 6, 2012 Revised under Project 2007-03 Revised

2 May 9, 2012 Adopted by Board of Trustees Revised

3 February 12, 2015 Adopted by Board of Trustees Revisions under Project 2014-03

3 November 19, 2015

FERC approved TOP-001-3. Docket No. RM15-16-000. Order No. 817.

Approved

4 February 9, 2017 Adopted by Board of Trustees Revised

4 April 17, 2017 FERC letter Order approved TOP-001-4. Docket No. RD17-4-000

5 TBD Adopted by Board of Trustees R19 and R22 retired under Project 2018-03 Standards Efficiency Review Retirements

6 TBD Adopted by the Board of Trustees






Description of Current Draft

Completed Actions Date


08/19/15


45-day formal comment period with initial ballot 08/27/18 - 10/17/18


45-day formal comment period with initial ballot June 2020




Term(s): None

Agenda Item 4dStandards Committee

June 17, 2020



A. Introduction Title: Transmission Operations

Number: TOP-001-56

Purpose: To prevent instability, uncontrolled separation, or Cascading outages that adversely impact the reliability of the Interconnection by ensuring prompt action to prevent or mitigate such occurrences.

Applicability:

1.1. Functional Entities:

4.1.1. Balancing Authority

4.1.2. Transmission Operator

4.1.3. Generator Operator

4.1.4. Distribution Provider

Effective Date: See Implementation Plan



B. Requirements and Measures R1. Each Transmission Operator shall act to maintain the reliability of its Transmission

Operator Area via its own actions or by issuing Operating Instructions. [Violation Risk Factor: High][Time Horizon: Same-Day Operations, Real-time Operations]

M1. Each Transmission Operator shall have and provide evidence which may include but is not limited to dated operator logs, dated records, dated and time-stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent documentation, that will be used to determine that it acted to maintain the reliability of its Transmission Operator Area via its own actions or by issuing Operating Instructions.

R2. Each Balancing Authority shall act to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions. [Violation Risk Factor: High][Time Horizon: Same-Day Operations, Real-time Operations]

M2. Each Balancing Authority shall have and provide evidence which may include but is not limited to dated operator logs, dated records, dated and time-stamped voice recordings or dated transcripts of voice recordings, electronic communications, or equivalent documentation, that will be used to determine that it acted to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions.

R3. Each Balancing Authority, Generator Operator, and Distribution Provider shall comply with each Operating Instruction issued by its Transmission Operator(s), unless such action cannot be physically implemented or it would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M3. Each Balancing Authority, Generator Operator, and Distribution Provider shall make available upon request, evidence that it complied with each Operating Instruction issued by the Transmission Operator(s) unless such action could not be physically implemented or it would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. In such cases, the Balancing Authority, Generator Operator, and Distribution Provider shall have and provide copies of the safety, equipment, regulatory, or statutory requirements as evidence for not complying with the Transmission Operator’s Operating Instruction. If such a situation has not occurred, the Balancing Authority, Generator Operator, or Distribution Provider may provide an attestation.

R4. Each Balancing Authority, Generator Operator, and Distribution Provider shall inform its Transmission Operator of its inability to comply with an Operating Instruction issued by its Transmission Operator. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]



M4. Each Balancing Authority, Generator Operator, and Distribution Provider shall make available upon request, evidence which may include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent evidence in electronic or hard copy format, that it informed its Transmission Operator of its inability to comply with its Operating Instruction issued. If such a situation has not occurred, the Balancing Authority, Generator Operator, or Distribution Provider may provide an attestation.

R5. Each Transmission Operator, Generator Operator, and Distribution Provider shall comply with each Operating Instruction issued by its Balancing Authority, unless such action cannot be physically implemented or it would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M5. Each Transmission Operator, Generator Operator, and Distribution Provider shall make available upon request, evidence that it complied with each Operating Instruction issued by its Balancing Authority unless such action could not be physically implemented or it would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. In such cases, the Transmission Operator, Generator Operator, and Distribution Provider shall have and provide copies of the safety, equipment, regulatory, or statutory requirements as evidence for not complying with the Balancing Authority’s Operating Instruction. If such a situation has not occurred, the Transmission Operator, Generator Operator, or Distribution Provider may provide an attestation.

R6. Each Transmission Operator, Generator Operator, and Distribution Provider shall inform its Balancing Authority of its inability to comply with an Operating Instruction issued by its Balancing Authority. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-Time Operations]

M6. Each Transmission Operator, Generator Operator, and Distribution Provider shall make available upon request, evidence which may include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or equivalent evidence in electronic or hard copy format, that it informed its Balancing Authority of its inability to comply with its Operating Instruction. If such a situation has not occurred, the Transmission Operator, Generator Operator, or Distribution Provider may provide an attestation.

R7. Each Transmission Operator shall 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 such assistance cannot be physically implemented or would violate safety, equipment, regulatory, or statutory requirements. [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]



M7. Each Transmission Operator shall make available upon request, evidence that comparable requested assistance, if able, was provided to other Transmission Operators within its Reliability Coordinator Area unless such assistance could not be physically implemented or would have violated safety, equipment, regulatory, or statutory requirements. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence in electronic or hard copy format. If no request for assistance was received, the Transmission Operator may provide an attestation.

R8. Each Transmission Operator shall 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. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-Time Operations]

M8. Each Transmission Operator shall make available upon request, evidence that it informed 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. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If no such situations have occurred, the Transmission Operator may provide an attestation.

R9. Each Balancing Authority and Transmission Operator shall 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 between the affected entities. [Violation Risk Factor: Medium] [Time Horizon: Operations Planning, Same-Day Operations, Real-Time Operations]

M9. Each Balancing Authority and Transmission Operator shall make available upon request, evidence that it notified 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. Such evidence could include but is not limited to dated operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence. If such a situation has not occurred, the Balancing Authority or Transmission Operator may provide an attestation.

R10. Each Transmission Operator shall perform the following for determining System Operating Limit (SOL) exceedances within its Transmission Operator Area: [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

10.1. Monitor Facilities within its Transmission Operator Area;



10.2. Monitor the status of Remedial Action Schemes within its Transmission Operator Area;

10.3. Monitor non-BES facilities within its Transmission Operator Area identified as necessary by the Transmission Operator;

10.4. Obtain and utilize status, voltages, and flow data for Facilities outside its Transmission Operator Area identified as necessary by the Transmission Operator;

10.5. Obtain and utilize the status of Remedial Action Schemes outside its Transmission Operator Area identified as necessary by the Transmission Operator; and

10.6. Obtain and utilize status, voltages, and flow data for non-BES facilities outside its Transmission Operator Area identified as necessary by the Transmission Operator.

M10. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to Energy Management System description documents, computer printouts, Supervisory Control and Data Acquisition (SCADA) data collection, or other equivalent evidence that will be used to confirm that it monitored or obtained and utilized data as required to determine any System Operating Limit (SOL) exceedances within its Transmission Operator Area.

R11. Each Balancing Authority shall monitor its Balancing Authority Area, including the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency. [Violation Risk Factor: High] [Time Horizon: Real-Time Operations]

M11. Each Balancing Authority shall have, and provide upon request, evidence that could include but is not limited to Energy Management System description documents, computer printouts, SCADA data collection, or other equivalent evidence that will be used to confirm that it monitors its Balancing Authority Area, including the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

R12. Each Transmission Operator shall not operate outside any identified Interconnection Reliability Operating Limit (IROL) for a continuous duration exceeding its associated IROL Tv. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M12. Each Transmission Operator shall make available evidence to show that for any occasion in which it operated outside any identified Interconnection Reliability Operating Limit (IROL), the continuous duration did not exceed its associated IROL Tv. Such evidence could include but is not limited to dated computer logs or reports in electronic or hard copy format specifying the date, time, duration, and details of the



excursion. If such a situation has not occurred, the Transmission Operator may provide an attestation that an event has not occurred.

R13. Each Transmission Operator shall ensure that a Real-time Assessment is performed at least once every 30 minutes. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M13. Each Transmission Operator shall have, and make available upon request, evidence to show it ensured that a Real-Time Assessment was performed at least once every 30 minutes. This evidence could include but is not limited to dated computer logs showing times the assessment was conducted, dated checklists, or other evidence.

R14. Each Transmission Operator shall initiate its Operating Plan to mitigate a SOL exceedance identified as part of its Real-time monitoring or Real-time Assessment. [Violation Risk Factor: High] [Time Horizon: Real-time Operations]

M14. Each Transmission Operator shall have evidence that it initiated its Operating Plan for mitigating SOL exceedances identified as part of its Real-time monitoring or Real-time Assessments. This evidence could include but is not limited to dated computer logs showing times the Operating Plan was initiated, dated checklists, or other evidence. Other evidence could include but is not limited to: Reliability Coordinator’s SOL methodology, system logs/records showing successfully mitigated SOL exceedances in conjunction with Operating Plans (e.g. mutually agreed operating protocols between TOPs and their Reliability Coordinator, Operating Procedures, Operating Processes, operating policies, generator redispatch logs, equipment settings for automatically switched equipment and reactive power/voltage control devices, switching schedules, etc.).

R15. Each Transmission Operator shall inform its Reliability Coordinator of actions taken to return the System to within limits when a SOL has been exceeded in accordance with its Reliability Coordinator’s SOL methodology. [Violation Risk Factor: Medium] [Time Horizon: Real-Time Operations]

M15. Each Transmission Operator shall make available evidence that it informed its Reliability Coordinator of actions taken to return the System to within limits when a SOL was exceeded in accordance with its Reliability Coordinator’s SOL methodology. Such evidence could include but is not limited to dated operator logs, electronic communications, voice recordings or transcripts of voice recordings, or dated computer printouts. If such a situation has not occurred, the Transmission Operator may provide an attestation.

R16. Each Transmission Operator shall provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]



M16. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to a documented procedure or equivalent evidence that will be used to confirm that the Transmission Operator has provided its System Operators with the authority to approve planned outages and maintenance of telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R17. Each Balancing Authority shall provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]

M17. Each Balancing Authority shall have, and provide upon request, evidence that could include but is not limited to a documented procedure or equivalent evidence that will be used to confirm that the Balancing Authority has provided its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R18. Each Transmission Operator shall operate to the most limiting parameter in instances where there is a difference in SOLs. [Violation Risk Factor: High] [Time Horizon: Operations Planning, Same-Day Operations, Real-time Operations]

M18. Each Transmission Operator shall have, and provide upon request, evidence that could include but is not limited to operator logs, voice recordings, electronic communications, or equivalent evidence that will be used to determine if it operated to the most limiting parameter in instances where there is a difference in SOLs.

R19. Reserved.

M19. Reserved.

R20. Each Transmission Operator shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from in order for it to perform its Real-time monitoring and Real-time Assessments. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M20. Each Transmission Operator shall have, and provide upon request, evidence that could include, but is not limited to, system specifications, system diagrams, or other documentation that lists its data exchange capabilities, including redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Balancing Authority, and the entities it has identified it needs data from



in order to perform its Real-time monitoring and Real-time Assessments as specified in the requirement.

R21. Each Transmission Operator shall test its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality at least once every 90 calendar days. If the test is unsuccessful, the Transmission Operator shall initiate action within two hours to restore redundant functionality. [Violation Risk Factor: Medium ] [Time Horizon: Operations Planning]

M21. Each Transmission Operator shall have, and provide upon request, evidence that it tested its primary Control Center data exchange capabilities specified in Requirement R20 for the redundant functionality, or experienced an event that demonstrated the redundant functionality; and, if the test was unsuccessful, initiated action within two hours to restore redundant functionality as specified in Requirement R21. Evidence could include, but is not limited to: dated and time-stamped test records, operator logs, voice recordings, or electronic communications.

R22. Reserved.

M22. Reserved.

R23. Each Balancing Authority shall have data exchange capabilities, with redundant and diversely routed data exchange infrastructure within the Balancing Authority's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Transmission Operator, and the entities it has identified it needs data from in order for it to perform its Real-time monitoring and analysis functions. [Violation Risk Factor: High] [Time Horizon: Same-Day Operations, Real-time Operations]

M23. Each Balancing Authority shall have, and provide upon request, evidence that could include, but is not limited to, system specifications, system diagrams, or other documentation that lists its data exchange capabilities, including redundant and diversely routed data exchange infrastructure within the Balancing Authority's primary Control Center, for the exchange of Real-time data with its Reliability Coordinator, Transmission Operator, and the entities it has identified it needs data from in order to perform its Real-time monitoring and analysis functions as specified in the requirement.

R24. Each Balancing Authority shall test its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality at least once every 90 calendar days. If the test is unsuccessful, the Balancing Authority shall initiate action within two hours to restore redundant functionality. [Violation Risk Factor: Medium ] [Time Horizon: Operations Planning]

R25. M24. Each Balancing Authority shall have, and provide upon request, evidence that it tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, or experienced an event that demonstrated the redundant functionality; and, if the test was unsuccessful, initiated



action within two hours to restore redundant functionality as specified in Requirement R24. Evidence could include, but is not limited to: dated and time-stamped test records, operator logs, voice recordings, or electronic communications.

R25. Each Transmission Operator shall use the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. [Violation Risk Factor: High ] [Time Horizon: Same-Day Operations, Real-time Operations, Operations Planning]

M25. Each Transmission Operator shall have, and provide upon request, evidence that it used the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis. Evidence could include, but is not limited to: Reliability Coordinator’s SOL methodology, Operating Plans, contingency sets, alarming and study reporting thresholds, operator logs, voice recordings or other equivalent evidence.




1.1. Compliance Enforcement Authority: “Compliance Enforcement Authority” means NERC or the Regional Entity, or any entity as otherwise designated by an Applicable Governmental Authority, in their respective roles of monitoring and/or enforcing compliance with mandatory and enforceable Reliability Standards in their respective jurisdictions.

1.2. Evidence Retention: The following evidence retention period(s) identify the period of time an entity is required to retain specific evidence to demonstrate compliance. For instances where the evidence retention period specified below is shorter than the time since the last audit, the Compliance Enforcement Authority may ask an entity to provide other evidence to show that it was compliant for the full-time period since the last audit.

The applicable entity shall keep data or evidence to show compliance as identified below unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Balancing Authority, Transmission Operator, Generator Operator, and Distribution Provider shall each keep data or evidence for each applicable Requirement R1 through R11, and Measure M1 through M11, for the current calendar year and one previous calendar year, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Transmission Operator shall retain evidence for three calendar years of any occasion in which it has exceeded an identified IROL and its associated IROL Tv as specified in Requirement R12 and Measure M12.

• Each Transmission Operator shall keep data or evidence for Requirement R13 and Measure M13 for a rolling 30-day period, unless directed by its Compliance Enforcement Authority to retain specific evidence for a longer period of time as part of an investigation.

• Each Transmission Operator shall retain evidence and that it initiated its Operating Plan to mitigate a SOL exceedance as specified in Requirement R14 and Measurement M14 for three calendar yearsrollingfor rolling 12 months.

• Each Transmission Operator and Balancing Authority shall each keep data or evidence for each applicable Requirement R15 through R18, and Measure M15 through M18 for the current calendar year and one



previous calendar year, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Transmission Operator shall keep data or evidence for Requirement R20 and Measure M20 for the current calendar year and one previous calendar year.

• Each Transmission Operator shall keep evidence for Requirement R21 and Measure M21 for the most recent twelve calendar months, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Balancing Authority shall keep data or evidence for Requirement R23 and Measure M23 for the current calendar year and one previous calendar year.

• Each Balancing Authority shall keep evidence for Requirement R24 and Measure M24 for the most recent twelve calendar months, with the exception of operator logs and voice recordings which shall be retained for a minimum of 90 calendar days.

• Each Transmission Operator shall retain evidence that it used the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis as specified in Requirement R25 and Measurement M25 for a rolling 12 months.

•

1.3. Compliance Monitoring and Enforcement Program As defined in the NERC Rules of Procedure, “Compliance Monitoring and Enforcement Program” refers to the identification of the processes that will be used to evaluate data or information for the purpose of assessing performance or outcomes with the associated Reliability Standard.






R1. N/A N/A N/A The Transmission Operator failed to act to maintain the reliability of its Transmission Operator Area via its own actions or by issuing Operating Instructions.

R2. N/A N/A N/A The Balancing Authority failed to act to maintain the reliability of its Balancing Authority Area via its own actions or by issuing Operating Instructions.

R3. N/A N/A N/A

The responsible entity did not comply with an Operating Instruction issued by the Transmission Operator, and such action could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R4. N/A N/A N/A The responsible entity did not inform its Transmission Operator of its inability to





comply with an Operating Instruction issued by its Transmission Operator.

R5. N/A N/A N/A The responsible entity did not comply with an Operating Instruction issued by the Balancing Authority, and such action could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R6. N/A N/A N/A The responsible entity did not inform its Balancing Authority of its inability to comply with an Operating Instruction issued by its Balancing Authority.

R7. N/A N/A N/A

The Transmission Operator did not provide comparable assistance to other Transmission Operators within its Reliability Coordinator Area, when requested and able, and the





requesting entity had implemented its Emergency procedures, and such actions could have been physically implemented and would not have violated safety, equipment, regulatory, or statutory requirements.

R8. The Transmission Operator did not inform one known impacted Transmission Operator or 5% or less of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform one known impacted

The Transmission Operator did not inform two known impacted Transmission Operators or more than 5% and less than or equal to 10% of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform two known impacted Balancing

The Transmission Operator did not inform three known impacted Transmission Operators or more than 10% and less than or equal to 15% of the known impacted Transmission Operators, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Transmission Operator Areas. OR, The Transmission Operator did not inform three known impacted Balancing

The Transmission Operator did not inform its Reliability Coordinator of its actual or expected operations that resulted in, or could have resulted in, an Emergency on those respective Transmission Operator Areas. OR The Transmission Operator did not inform four or more known impacted Transmission Operators or more than 15% of the known impacted Transmission Operators of its actual or expected





Balancing Authorities or 5% or less of the known impacted Balancing Authorities, whichever is greater, of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Balancing Authority Areas.



operations that resulted in, or could have resulted in, an Emergency on those respective Transmission Operator Areas. OR, The Transmission Operator did not inform four or more known impacted Balancing Authorities or more than 15% of the known impacted Balancing Authorities of its actual or expected operations that resulted in, or could have resulted in, an Emergency on respective Balancing Authority Areas.

R9. The responsible entity did not notify one known impacted interconnected entity or 5% or less of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control

The responsible entity did not notify two known impacted interconnected entities or more than 5% and less than or equal to 10% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30

The responsible entity did not notify three known impacted interconnected entities or more than 10% and less than or equal to 15% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30

The responsible entity did not notify its Reliability Coordinator of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels.





equipment, monitoring and assessment capabilities, or associated communication channels between the affected entities.



OR, The responsible entity did not notify four or more known impacted interconnected entities or more than 15% of the known impacted entities, whichever is greater, of a planned outage, or an unplanned outage of 30 minutes or more, for telemetering and control equipment, monitoring and assessment capabilities, or associated communication channels between the affected entities.

R10. The Transmission Operator did not monitor, obtain, or utilize one of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize two of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize three of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10, Part 10.1 through 10.6.

The Transmission Operator did not monitor, obtain, or utilize four or more of the items required or identified as necessary by the Transmission Operator and listed in Requirement R10 Part 10.1 through 10.6.





R11. N/A N/A The Balancing Authority did not monitor the status of Remedial Action Schemes that impact generation or Load, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

The Balancing Authority did not monitor its Balancing Authority Area, in order to maintain generation-Load-interchange balance within its Balancing Authority Area and support Interconnection frequency.

R12. N/A N/A N/A The Transmission Operator exceeded an identified Interconnection Reliability Operating Limit (IROL) for a continuous duration greater than its associated IROL Tv.

R13. For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for one 30-minute period within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for two 30-minute periods within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for three 30-minute periods within that 24-hour period.

For any sample 24-hour period within the 30-day retention period, the Transmission Operator’s Real-time Assessment was not conducted for four or more 30-minute periods within that 24-hour period.

R14. N/A N/A N/A The Transmission Operator did not initiate its Operating





Plan for mitigating a SOL exceedance identified as part of its Real-time monitoring or Real-time Assessment

R15. N/A N/A N/A The Transmission Operator did not inform in accordance with its Reliability Coordinator’s SOL methodology its Reliability Coordinator of actions taken to return the System to within limits when a SOL had been exceeded.

R16. N/A N/A N/A The Transmission Operator did not provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.





R17. N/A N/A N/A The Balancing Authority did not provide its System Operators with the authority to approve planned outages and maintenance of its telemetering and control equipment, monitoring and assessment capabilities, and associated communication channels between affected entities.

R18. N/A N/A N/A The Transmission Operator failed to operate to the most limiting parameter in instances where there was a difference in SOLs.

R19. Reserved.

R20. N/A N/A The Transmission Operator had data exchange capabilities with its Reliability Coordinator, Balancing Authority, and identified entities for performing Real-time

The Transmission Operator did not have data exchange capabilities with its Reliability Coordinator, Balancing Authority, and identified entities for performing Real-time





monitoring and Real-time Assessments, but did not have redundant and diversely routed data exchange infrastructure within the Transmission Operator's primary Control Center, as specified in the Requirement.

monitoring and Real-time Assessments as specified in the Requirement.

R21. The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality, but did so more than 90 calendar days but less than or equal to 120 calendar days since the previous test; OR The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement



The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality, but did so more than 180 calendar days since the previous test;

OR

The Transmission Operator did not test its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality;





R20 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, initiated action to restore the redundant functionality in more than 2 hours and less than or equal to 4 hours.



OR The Transmission Operator tested its primary Control Center data exchange capabilities specified in Requirement R20 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, did not initiate action within 8 hours to restore the redundant functionality.

R22. Reserved.

R23. N/A N/A The Balancing Authority had data exchange capabilities with its Reliability Coordinator, Transmission Operator, and identified entities for performing Real-time monitoring and analysis functions, but did not have redundant and diversely routed data exchange infrastructure

The Balancing Authority did not have data exchange capabilities with its Reliability Coordinator, Transmission Operator, and identified entities for performing Real-time monitoring and analysis functions as specified in the Requirement.





within the Balancing Authority's primary Control Center, as specified in the Requirement.

R24. The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, but did so more than 90 calendar days but less than or equal to 120 calendar days since the previous test; OR The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, initiated action to restore the redundant



The Balancing Authority tested its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality, but did so more than 180 calendar days since the previous test;

OR

The Balancing Authority did not test its primary Control Center data exchange capabilities specified in Requirement R23 for redundant functionality;

OR The Balancing Authority tested its primary Control Center data exchange capabilities specified in





functionality in more than 2 hours and less than or equal to 4 hours.



Requirement R23 for redundant functionality at least once every 90 calendar days but, following an unsuccessful test, did not initiate action within 8 hours to restore the redundant functionality.

R25. The Transmission Operator failed to use the applicable Reliability Coordinator’s SOL methodology when determining SOL exceedances for Real-time Assessments, Real-time Monitoring, and Operational Planning Analysis.



D. Regional Variances None.

E. Associated Documents The Project 2014-03 SDT has created the SOL Exceedance White Paper as guidance on SOL issues and the URL for that document is: http://www.nerc.com/pa/stand/Pages/TOP0013RI.aspx. Operating Plan - An Operating Plan includes general Operating Processes and specific Operating Procedures. It may be an overview document which provides a prescription for an Operating Plan for the next-day, or it may be a specific plan to address a specific SOL or IROL exceedance identified in the Operational Planning Analysis (OPA). Consistent with the NERC definition, Operating Plans can be general in nature, or they can be specific plans to address specific reliability issues. The use of the term Operating Plan in the revised TOP/IRO standards allows room for both. An Operating Plan references processes and procedures, including electronic data exchange, which are available to the System Operator on a daily basis to allow the operator to reliably address conditions which may arise throughout the day. It is valid for tomorrow, the day after, and the day after that. Operating Plans should be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an OPA or a Real-time Assessment (RTA). As the definition in the Glossary of Terms states, a restoration plan is an example of an Operating Plan. It contains all the overarching principles that the System Operator needs to work his/her way through the restoration process. It is not a specific document written for a specific blackout scenario but rather a collection of tools consisting of processes, procedures, and automated software systems that are available to the operator to use in restoring the system. An Operating Plan can in turn be looked upon in a similar manner. It does not contain a prescription for the specific set-up for tomorrow but contains a treatment of all the processes, procedures, and automated software systems that are at the operator’s disposal. The existence of an Operating Plan, however, does not preclude the need for creating specific action plans for specific SOL or IROL exceedances identified in the OPA. When a Reliability Coordinator performs an OPA, the analysis may reveal instances of possible SOL or IROL exceedances for pre- or post-Contingency conditions. In these instances, Reliability Coordinators are expected to ensure that there are plans in place to prevent or mitigate those SOLs or IROLs, should those operating conditions be encountered the next day. The Operating Plan may contain a description of the process by which specific prevention or mitigation plans for day-to-day SOL or IROL exceedances identified in the OPA are handled and communicated. This approach could alleviate any potential administrative burden associated with perceived requirements for continual day-to-day updating of “the Operating Plan document” for compliance purposes.

http://www.nerc.com/pa/stand/Pages/TOP0013RI.aspx



Version History Version Date Action Change Tracking

0 April 1, 2005 Effective Date New

0 August 8, 2005 Removed “Proposed” from Effective Date

Errata

1 November 1, 2006

Adopted by Board of Trustees Revised

1a May 12, 2010 Added Appendix 1 – Interpretation of R8 approved by Board of Trustees on May 12, 2010

Interpretation

1a September 15, 2011

FERC Order issued approved the Interpretation of R8 (FERC Order became effective November 21, 2011)

Interpretation

2 May 6, 2012 Revised under Project 2007-03 Revised

2 May 9, 2012 Adopted by Board of Trustees Revised

3 February 12, 2015 Adopted by Board of Trustees Revisions under Project 2014-03

3 November 19, 2015

FERC approved TOP-001-3. Docket No. RM15-16-000. Order No. 817.

Approved

4 February 9, 2017 Adopted by Board of Trustees Revised

4 April 17, 2017 FERC letter Order approved TOP-001-4. Docket No. RD17-4-000

5 TBD Adopted by Board of Trustees R19 and R22 retired under Project 2018-03 Standards Efficiency Review Retirements

6 TBD Adopted by the Board of Trustees



Guidelines and Technical Basis None. Rationale Rationale text from the development of TOP-001-3 in Project 2014-03 and TOP-001-4 in Project 2016-01 follows. Additional information can be found on the Project 2014-03 and Project 2016-01 pages. Rationale for Requirement R3: The phrase ‘cannot be physically implemented’ means that a Transmission Operator may request something to be done that is not physically possible due to its lack of knowledge of the system involved. Rationale for Requirement R10: New proposed Requirement R10 is derived from approved IRO-003-2, Requirement R1, adapted to the Transmission Operator Area. This new requirement is in response to NOPR paragraph 60 concerning monitoring capabilities for the Transmission Operator. New Requirement R11 covers the Balancing Authorities. Monitoring of external systems can be accomplished via data links. The revised requirement addresses directives for Transmission Operator (TOP) monitoring of some non-Bulk Electric System (BES) facilities as necessary for determining System Operating Limit (SOL) exceedances (FERC Order No. 817 Para 35-36). The proposed requirement corresponds with approved IRO-002-4 Requirement R4 (proposed IRO-002-5 Requirement R5), which specifies the Reliability Coordinator's (RC) monitoring responsibilities for determining SOL exceedances. The intent of the requirement is to ensure that all facilities (i.e., BES and non-BES) that can adversely impact reliability of the BES are monitored. As used in TOP and IRO Reliability Standards, monitoring involves observing operating status and operating values in Real-time for awareness of system conditions. The facilities that are necessary for determining SOL exceedances should be either designated as part of the BES, or otherwise be incorporated into monitoring when identified by planning and operating studies such as the Operational Planning Analysis (OPA) required by TOP-002-4 Requirement R1 and IRO-008-2 Requirement R1. The SDT recognizes that not all non-BES facilities that a TOP considers necessary for its monitoring needs will need to be included in the BES. The non-BES facilities that the TOP is required to monitor are only those that are necessary for the TOP to determine SOL exceedances within its Transmission Operator Area. TOPs perform various analyses and studies as part of their functional obligations that could lead to identification of non-BES facilities that should be monitored for determining SOL exceedances. Examples include:

• OPA;

• Real-time Assessments (RTA);



• Analysis performed by the TOP as part of BES Exception processing for including a facility in the BES; and

• Analysis which may be specified in the RC's outage coordination process that leads the TOP to identify a non-BES facility that should be temporarily monitored for determining SOL exceedances.

TOP-003-3 Requirement R1 specifies that the TOP shall develop a data specification which includes data and information needed by the TOP to support its OPAs, Real-time monitoring, and RTAs. This includes non-BES data and external network data as deemed necessary by the TOP. The format of the proposed requirement has been changed from the approved standard to more clearly indicate which monitoring activities are required to be performed. Rationale for Requirement R13: The new Requirement R13 is in response to NOPR paragraphs 55 and 60 concerning Real-time analysis responsibilities for Transmission Operators and is copied from approved IRO-008-1, Requirement R2. The Transmission Operator’s Operating Plan will describe how to perform the Real-time Assessment. The Operating Plan should contain instructions as to how to perform Operational Planning Analysis and Real-time Assessment with detailed instructions and timing requirements as to how 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. Rationale for Requirement R14: The original Requirement R8 was deleted and original Requirements R9 and R11 were revised in order to respond to NOPR paragraph 42 which raised the issue of handling all SOLs and not just a sub-set of SOLs. The SDT has developed a white paper on SOL exceedances that explains its intent on what needs to be contained in such an Operating Plan. These Operating Plans are developed and documented in advance of Real-time and may be developed from Operational Planning Assessments required per proposed TOP-002-4 or other assessments. Operating Plans could be augmented by temporary operating guides which outline prevention/mitigation plans for specific situations which are identified day-to-day in an Operational Planning Assessment or a Real-time Assessment. The intent is to have a plan and philosophy that can be followed by an operator. Rationale for Requirements R16 and R17: In response to IERP Report recommendation 3 on authority.



Rationale for Requirement R18: Moved from approved IRO-005-3.1a, Requirement R10. Transmission Service Provider, Distribution Provider, Load-Serving Entity, Generator Operator, and Purchasing-Selling Entity are deleted as those entities will receive instructions on limits from the responsible entities cited in the requirement. Note – Derived limits replaced by SOLs for clarity and specificity. SOLs include voltage, Stability, and thermal limits and are thus the most limiting factor. Rationale for Requirements R19 and R20 (R19, R20, R22, and R23 in TOP-001-4): [Note: Requirement R19 proposed for retirement under Project 2018-03 Standards Efficiency Review Retirements.] The proposed changes address directives for redundancy and diverse routing of data exchange capabilities (FERC Order No. 817 Para 47). Redundant and diversely routed data exchange capabilities consist of data exchange infrastructure components (e.g., switches, routers, servers, power supplies, and network cabling and communication paths between these components in the primary Control Center for the exchange of system operating data) that will provide continued functionality despite failure or malfunction of an individual component within the Transmission Operator's (TOP) primary Control Center. Redundant and diversely routed data exchange capabilities preclude single points of failure in primary Control Center data exchange infrastructure from halting the flow of Real-time data. Requirement R20 does not require automatic or instantaneous fail-over of data exchange capabilities. Redundancy and diverse routing may be achieved in various ways depending on the arrangement of the infrastructure or hardware within the TOP's primary Control Center. The reliability objective of redundancy is to provide for continued data exchange functionality during outages, maintenance, or testing of data exchange infrastructure. For periods of planned or unplanned outages of individual data exchange components, the proposed requirements do not require additional redundant data exchange infrastructure components solely to provide for redundancy. Infrastructure that is not within the TOP's primary Control Center is not addressed by the proposed requirement. Rationale for Requirement R21: The proposed requirement addresses directives for testing of data exchange capabilities used in primary Control Centers (FERC Order No. 817 Para 51). A test for redundant functionality demonstrates that data exchange capabilities will continue to operate despite the malfunction or failure of an individual component (e.g., switches, routers, servers, power supplies, and network cabling and communication paths between these components in the primary Control Center for the exchange of system operating data). An entity's testing practices should, over time, examine the various failure modes of its data



exchange capabilities. When an actual event successfully exercises the redundant functionality, it can be considered a test for the purposes of the proposed requirement. Rationale for Requirements R22 and R23: [Note: Requirement R22 proposed for retirement under Project 2018-03 Standards Efficiency Review Retirements] The proposed changes address directives for redundancy and diverse routing of data exchange capabilities (FERC Order No. 817 Para 47). Redundant and diversely routed data exchange capabilities consist of data exchange infrastructure components (e.g., switches, routers, servers, power supplies, and network cabling and communication paths between these components in the primary Control Center for the exchange of system operating data) that will provide continued functionality despite failure or malfunction of an individual component within the Balancing Authority's (BA) primary Control Center. Redundant and diversely routed data exchange capabilities preclude single points of failure in primary Control Center data exchange infrastructure from halting the flow of Real-time data. Requirement R23 does not require automatic or instantaneous fail-over of data exchange capabilities. Redundancy and diverse routing may be achieved in various ways depending on the arrangement of the infrastructure or hardware within the BA's primary Control Center. The reliability objective of redundancy is to provide for continued data exchange functionality during outages, maintenance, or testing of data exchange infrastructure. For periods of planned or unplanned outages of individual data exchange components, the proposed requirements do not require additional redundant data exchange infrastructure components solely to provide for redundancy. Infrastructure that is not within the BA's primary Control Center is not addressed by the proposed requirement. Rationale for Requirement R24: The proposed requirement addresses directives for testing of data exchange capabilities used in primary Control Centers (FERC Order No. 817 Para 51). A test for redundant functionality demonstrates that data exchange capabilities will continue to operate despite the malfunction or failure of an individual component(e.g., switches, routers, servers, power supplies, and network cabling and communication paths between these components in the primary Control Center for the exchange of system operating data). An entity's testing practices should, over time, examine the various failure modes of its data exchange capabilities. When an actual event successfully exercises the redundant functionality, it can be considered a test for the purposes of the proposed requirement.


June 17, 2020

Project 2019-06 Cold Weather SAR Drafting Team Action Authorize soliciting additional nominations for Project 2019-06 Cold Weather SAR drafting team (DT) for a 15-day nomination period. Background In July 2019, the FERC and NERC staff report titled The South Central United States Cold Weather Bulk Electronic System Event of January 17, 2018 (Report) was released. Following the report, Southwest Power Pool, Inc. (SPP) submitted a SAR proposing a new standard development project to review and address the recommendations in the Report. The industry need for this SAR according to SPP is to enhance the reliability of the BES during cold weather events. At its October 2, 2019 special call, the Standards Committee (SC) accepted the SAR, authorized posting the SAR for 30 days, and authorized solicitations of members for a SAR drafting team for a 30-day nomination period. On December 18, 2019, the SC appointed the current Cold Weather SAR DT. The SAR DT lacks representation of small entities and requests the SC authorize solicitation for additional nominations. The requested 15-day nomination period provides adequate time to solicit nominations while allowing NERC to present recommendations at the July SC meeting. Below is the roster for the current Cold Weather SAR DT.

Project 2019-06 Standards Authorization Request Drafting Team Roster

Name Entity

Chair Matthew Harward Southwest Power Pool, Inc.

Vice Chair Matt Averett Southern Company

Members Alan Allgower ERCOT

David Daniels American Electric Power

Chris Dibble Dominion Energy

Samuel J. Dwyer, IV Ameren

Venona Greaff Ingleside Cogeneration LP (Occidental Energy)

Cameron Lawson Tennessee Valley Authority

Kenneth Luebbert Evergy, Inc.

Project 2019-06 Standards Authorization Request Drafting Team Roster

Name Entity

Joshua Netherton MISO

Don Urban ReliabilityFirst


June 17, 2020

Project 2020-01 Modifications to MOD-032-1 Action Appoint chair, vice chair, and members to the Project 2020-01 Modifications to MOD-032-1 Standard Authorization Request (SAR) drafting team, as recommended by NERC staff. Background With the penetration of distributed energy resources (DER) continually increasing across the continent, it is imperative that the risk DER pose to the reliability of the Bulk Power System be minimized by improving the modeling of aggregate DER in planning studies. The System Planning Impacts from Distributed Energy Resources Working Group (SPIDERWG) reviewed MOD-032-1 Data for Power System Modeling and Analysis and developed a SAR requesting modifications be made to the standard to address the collecting and reporting of aggregate data for DER. This data is necessary to support the development of accurate interconnection-wide base cases for the planning horizon. The SPIDERWG presented its SAR to the Planning Committee (PC) during its June 2019 meeting, and the PC appointed reviewers. Based on the feedback from the PC reviewers, the SPIDERWG revised the SAR and presented it to the PC at its December 2019 meeting. The PC endorsed the SAR, and recommended it move forward to the NERC Standards Committee. The Standards Committee accepted the SAR and authorized soliciting for members for the SAR DT on March 18, 2020. From March 24 to April 24, 2020, NERC solicited nominations for a SAR drafting team. NERC staff received nineteen (19) nominations and recommends twelve (12) individuals with the requisite background, experience, and skills necessary for membership on the SAR drafting team.


June 17, 2020

Standards Committee Training Documentation Action Endorse a project for the Standards Committee Process Subcommittee (SCPS) to identify and document relevant materials for orientation and/or training for Standards Committee (SC) members, making recommendations for enhancements as necessary. Background A discussion at the March 18, 2020 SC meeting regarding Drafting Team Selection Criteria brought to light a list of criteria the SC should consider when selecting drafting team members. This list of criteria is contained in the Drafting Team Scope document, which although available on the NERC website, is not directly provided to SC members or referenced in any of the SC documents provided to new members. In order to ensure all SC members have knowledge and understanding of their duties as members, all members should be provided consistent training on the relevant guides, policies and governing documents. There are several sources of information that are necessary for SC members to have access to, knowledge and full understanding of in order to effectively fulfill their duties. To ensure a consistent approach to new member orientation, an inventory of relevant materials should be developed, gaps identitifed and recommendations made as necessary.


June, 17 2020

NERC Legal and Regulatory Update April 8, 2020 – June 3, 2020

NERC FILINGS TO FERC SUBMITTED SINCE LAST SC UPDATE

FERC Docket No. Filing Description FERC Submittal

Date

RD20-8-000

Petition for approval of erratum to TPL-001-5 NERC submitted a petition for approval of erratum to Reliability Standard TPL-001-5.

4/23/20

RM19-16-000

Withdrawal of proposed Reliability Standard VAR-001-6 Notice of withdrawal by NERC of its petition for approval of proposed Reliability Standard VAR-001-6.

5/14/20

RM19-20-000

Response to Data Request regarding BAL-002-WECC-3 NERC and WECC submit a response to FERC's data request regarding proposed regional Reliability Standard BAL-002-WECC-3 (Contingency Reserve).

Attachment 1 Attachment 2

5/18/20

FERC ISSUANCES SINCE LAST SC UPDATE

FERC Docket No. Issuance Description FERC Issuance

Date

RM15-4-000, RM16-22-000, RM17-13-000,

RD18-4-000

Order Granting Motion to Defer Certain Reliability Standards Implementation FERC issued an order granting NERC’s motion to delay upcoming implementation deadlines of certain Reliability Standards in response to coronavirus-related disruptions.

4/17/20

RD20-5-000

Letter order approving BAL-001-TRE-2 FERC issues a letter order approving Reliability Standard BAL-001-TRE-2.

5/19/20

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/TPL-001-5.1%20Package.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/TPL-001-5.1%20Package.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Notice%20of%20Withdrawal%20VAR-001-6.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Notice%20of%20Withdrawal%20VAR-001-6.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Ltr%20to%20FERC%20Encl%20Response%20to%20Data%20Request%20RM19-20.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Ltr%20to%20FERC%20Encl%20Response%20to%20Data%20Request%20RM19-20.pdf

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Attachment%201%20%20RM19-20-%20WECC%20RSG%20BA%20Data.xlsx

https://www.nerc.com/FilingsOrders/us/NERC%20Filings%20to%20FERC%20DL/Attachment%202%20%20RM19-20%20DR%20-%20WI%20M-4%20Events.xlsx

https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/order%20granting%20motion%20to%20defer%20the%20implementation%20dates.pdf

https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/order%20granting%20motion%20to%20defer%20the%20implementation%20dates.pdf

https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/20200519-3053(34086198).pdf

https://www.nerc.com/FilingsOrders/us/FERCOrdersRules/20200519-3053(34086198).pdf

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NERC PLANNED UPCOMING FILINGS

FERC Docket No. Filing Description Planned Filing

Date

TBD Petition for Approval of Reliability Standard CIP-002-6 June 12, 2020

RD20-2-000 CIP SDT Schedule Update June 19, 2020

RM20-8-000 Comments on FERC Notice of Inquiry Re: Virtualization and Cloud Computing (deadline extended) July 1, 2020


Standards Committee Expectations Approved by Standards Committee January 12, 2012

Background Standards Committee (SC) members are elected by members of their segment of the Registered Ballot Body, to help the SC fulfill its purpose. According to the Standards Committee Charter, the SC’s purpose is:

In compliance with the NERC Reliability Standards Development Procedure, the Standards Committee manages the NERC standards development process for the North American-wide reliability standards with the support of the NERC staff to achieve broad bulk power system reliability goals for the industry. The Standards Committee protects the integrity and credibility of the standards development process.

The purpose of this document is to outline the key considerations that each member of the SC must make in fulfilling his or her duties. Each member is accountable to the members of the Segment that elected them, other members of the SC, and the NERC Board of Trustees for carrying out their responsibilities in accordance with this document.

Expectations of Standards Committee Members 1. SC members represent their segment, not their organization or personal views. Each member is

expected to identify and use mechanisms for being in contact with members of the segment inorder to maintain a current perspective of the views, concerns, and input from that segment. NERCcan provide mechanisms to support communications if an SC member requests such assistance.

2. SC members base their decisions on what is best for reliability and must consider not only what isbest for their segment, but also what is in the best interest of the broader industry and reliability.

3. SC members should make every effort to attend scheduled meetings, and when not available arerequired to identify and brief a proxy from the same segment. SC business cannot be conducted inthe absence of a quorum, and it is essential that each SC member make a commitment to beingpresent.

4. SC members should not leverage or attempt to leverage their position on the SC to influence theoutcome of standards projects.

5. The role of the SC is to manage the standards process and the quality of the output, not thetechnical content of standards.

Agenda Item 9a Standards Committee

June 17, 2020

https://www.nerc.com/comm/SC/Documents/SC_Charter.pdf

Parliamentary Procedures

Agenda Item 9d Standards Committee

June 17, 2020

Based on Robert’s Rules of Order, Newly Revised, 11th Edition, plus “Organization and Procedures Manual for the NERC Standing Committees”

Motions Unless noted otherwise, all procedures require a “second” to enable discussion.

When you want to… Procedure Debatable Comments Raise an issue for discussion

Move Yes The main action that begins a debate.

Revise a Motion currently under discussion

Amend Yes Takes precedence over discussion of main motion. Motions to amend an amendment are allowed, but not any further. The amendment must be germane to the main motion, and cannot reverse the intent of the main motion.

Reconsider a Motion already approved

Reconsider Yes Allowed only by member who voted on the prevailing side of the original motion.

End debate Call for the Question or End Debate

No If the Chair senses that the committee is ready to vote, he may say “if there are no objections, we will now vote on the Motion.” The vote is subject to a 2/3 majority approval. Also, any member may call the question. This motion is not debatable. The vote is subject to a 2/3 vote.

Record each member’s vote on a Motion

Request a Roll Call Vote

No Takes precedence over main motion. No debate allowed, but the members must approve by 2/3 majority.

Postpone discussion until later in the meeting

Lay on the Table Yes Takes precedence over main motion. Used only to postpone discussion until later in the meeting.

Postpone discussion until a future date

Postpone until Yes Takes precedence over main motion. Debatable only regarding the date (and time) at which to bring the Motion back for further discussion.

Remove the motion for any further consideration

Postpone indefinitely

Yes Takes precedence over main motion. Debate can extend to the discussion of the main motion. If approved, it effectively “kills” the motion. Useful for disposing of a badly chosen motion that can not be adopted or rejected without undesirable consequences.

Request a review of procedure

Point of order No Second not required. The Chair or secretary shall review the parliamentary procedure used during the discussion of the Motion.

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Notes on Motions Seconds. A Motion must have a second to ensure that at least two members wish to discuss the issue. The “seconder” is not recorded in the minutes. Neither are motions that do not receive a second.

Announcement by the Chair. The Chair should announce the Motion before debate begins. This ensures that the wording is understood by the membership. Once the Motion is announced and seconded, the Committee “owns” the motion, and must deal with it according to parliamentary procedure.

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Voting Voting Method When Used How Recorded in Minutes Unanimous Consent The standard practice.

When the Chair senses that the Committee is substantially in agreement, and the Motion needed little or no debate. No actual vote is taken.

The minutes show “by unanimous consent.”

Vote by Voice The standard practice. The minutes show Approved or Not Approved (or Failed).

Vote by Show of Hands (tally)

To record the number of votes on each side when an issue has engendered substantial debate or appears to be divisive. Also used when a Voice Vote is inconclusive. (The Chair should ask for a Vote by Show of Hands when requested by a member).

The minutes show both vote totals, and then Approved or Not Approved (or Failed).

Vote by Roll Call To record each member’s vote. Each member is called upon by the Secretary, and the member indicates either “Yes,” “No,” or “Present” if abstaining.

The minutes will include the list of members, how each voted or abstained, and the vote totals. Those members for which a “Yes,” “No,” or “Present” is not shown are considered absent for the vote.

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