Agenda Real Time Operating Subcommittee...2021/02/09 · a. Synchronized Measurement Working Group...

RELIABILITY | RESILIENCE | SECURITY

Agenda Real Time Operating Subcommittee February 9, 2021| 11:00 a.m. – 5:00 p.m. Eastern WebEx Only Dial-in Number: + 1-415-655-0002 US Toll (Canadian Toll) + 1-416-915-8942 Meeting Number Access Code: 180 080 6204 | Security Code: 02092021 Introductions and Vice Chair’s Remarks NERC Antitrust Compliance Guidelines, Public Announcement, and Participant Conduct Policy Agenda

1. Administrative

a. Arrangements, Safety Briefing – Vice Chair Jimmy Hartmann,

b. Announcement of Quorum – Secretary Darrell Moore, NERC

i. Real Time Operating Subcommittee (RTOS) Roster*

(1) Updates

c. Parliamentary Procedures* – Secretary

d. Balancing Authority-to-Reliability Coordinator Mapping* – Secretary

e. Future Meetings – Secretary

i. May 5, 2021 | WebEx

ii. September 14, 2021 | WebEx

iii. Schedule future meetings

2. Meeting Minutes* (Approve) – Vice Chair Hartmann

a. Minutes of November 4, 2020 Real Time Operating Subcommittee Meeting

3. Reliability Plans* Vice Chair Hartmann

a. Periodic Review of Reliability Plans

i. Guideline for Approving Regional and Reliability Coordinator Reliability Plans*

b. New or Revised Reliability Plans for Endorsement

i. NPCC Regional Reliability Plan* – Lacy Skinner

ii. SPP West RC* – Bryan Wood

iii. RC West* – Tim Beach

iv. FRCC* – Raj Venkat

https://nerc.webex.com/nerc/j.php?MTID=m1c4f181dd814f69473c41f5f5a37aa3c

https://www.nerc.com/comm/PCGC/Documents/NERC_Antitrust_Compliance_Guidelines.pdf

https://www.nerc.com/comm/PCGC/Documents/NERC_Public_Announcement.pdf

https://www.nerc.com/comm/PCGC/Documents/NERC_Participant_Conduct_Policy.pdf

https://www.nerc.com/comm/OC/Operating%20Reliability%20Subcommittee%20ORS%202013/ORS_Minutes_Nov_4_2020.pdf

Agenda | Real Time Operating Subcommittee Meeting | February 9, 2021 2

4. Review RTOS Work Plan* – Vice Chair Hartmann

a. Review 2021 RTOS Work Plan

5. RTOS Scope* (Ratify) – Vice Chair Hartmann

6. Reliability Guideline: Gas and Electrical Operational Coordination Considerations* (Review) – All

a. RSTC approved to post for comments. Comment period December 15, 2020 – January 29, 2021. Review comments* – Vice Chair Hartmann

7. Reliability and Security Technical Committee (RSTC) Update* – Steve Crutchfield, NERC

a. RSTC 2021 Work Plan Update*

8. Synchronized Measurement Subcommittee (SMS) Update* – Timothy Fritch, TVA

a. Synchronized Measurement Working Group (SMWG) Scope* (Approve)

9. Resources Subcommittee (RS) Update to RTOS – Chair Greg Park, NWPP

a. Review of any abnormal frequency events identified by the RS Frequency Subcommittee

b. Report out on Inadvertent Accumulation

10. Interconnection Frequency Monitoring

a. Reference Guideline Update (Memorialize Document) – Chris Pilong, Kyle Russel, Terry Williams (get most recent guideline)

b. Frequency Monitor Reports and Frequency Excursions – All

i. Eastern – Terry Williams

ii. ERCOT – Jimmy Hartmann

iii. Western – Tim Reynolds

iv. Quebec – Maxime Nadeau

c. RTOS will vote to retire or amend the Frequency Monitor role for the Eastern Interconnection – All

11. GridEx VI Update* – Kate Ledesma, E-ISAC – Kate Ledesma

12. IDC SC Update – Chris Wakefield, Southern Company

13. Review Current Time Error Monitor and GMD Monitor – All

Closed Session

14. EISAC Update – Matt Duncan

15. SAFNR v3 Update – Darrell Moore, Mike Legatt, ResilientGrid

16. Operations Review – All

a. Operations Review

i. Include any relevant pandemic response plan changes heading into the spring

b. Use of Proxy Flowgate

Agenda | Real Time Operating Subcommittee Meeting | February 9, 2021 3

c. Energy Emergency Alert Level 3

17. Grid Security Emergency (GSE) Communications – Task Force

a. Volunteers:

i. John Norden

ii. Chris Wakefield

iii. Asher Steed

b. Draft NERC Hotline and Reliability Coordinator Emergency Procedures* (Review)

18. Round Table Open Discussion (Open) – All

a. NERC Reliability Coordinator Emergency Conference Call Procedure; Appendix A: Contacts Update – Darrell Moore

b. Closed Meetings (Discussion) – All *Background materials included.


Antitrust Compliance Guidelines

I. GeneralIt is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonablyrestrains competition. This policy requires the avoidance of any conduct that violates, or that mightappear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreementbetween or among competitors regarding prices, availability of service, product design, terms of sale,division of markets, allocation of customers or any other activity that unreasonably restrains competition.

It is the responsibility of every NERC participant and employee who may in any way affect NERC’s compliance with the antitrust laws to carry out this commitment.

Antitrust laws are complex and subject to court interpretation that can vary over time and from one court to another. The purpose of these guidelines is to alert NERC participants and employees to potential antitrust problems and to set forth policies to be followed with respect to activities that may involve antitrust considerations. In some instances, the NERC policy contained in these guidelines is stricter than the applicable antitrust laws. Any NERC participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NERC’s antitrust compliance policy is implicated in any situation should consult NERC’s General Counsel immediately.

II. Prohibited ActivitiesParticipants in NERC activities (including those of its committees and subgroups) should refrain from thefollowing when acting in their capacity as participants in NERC activities (e.g., at NERC meetings,conference calls and in informal discussions):

• Discussions involving pricing information, especially margin (profit) and internal costinformation and participants’ expectations as to their future prices or internal costs.

• Discussions of a participant’s marketing strategies.

• Discussions regarding how customers and geographical areas are to be divided amongcompetitors.

• Discussions concerning the exclusion of competitors from markets.

• Discussions concerning boycotting or group refusals to deal with competitors, vendors orsuppliers.

• Any other matters that do not clearly fall within these guidelines should be reviewed withNERC’s General Counsel before being discussed.

NERC Antitrust Compliance Guidelines 2

III. Activities That Are PermittedFrom time to time decisions or actions of NERC (including those of its committees and subgroups) mayhave a negative impact on particular entities and thus in that sense adversely impact competition.Decisions and actions by NERC (including its committees and subgroups) should only be undertaken forthe purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If youdo not have a legitimate purpose consistent with this objective for discussing a matter, please refrainfrom discussing the matter during NERC meetings and in other NERC-related communications.

You should also ensure that NERC procedures, including those set forth in NERC’s Certificate of Incorporation, Bylaws, and Rules of Procedure are followed in conducting NERC business.

In addition, all discussions in NERC meetings and other NERC-related communications should be within the scope of the mandate for or assignment to the particular NERC committee or subgroup, as well as within the scope of the published agenda for the meeting.

No decisions should be made nor any actions taken in NERC activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants. In particular, decisions with respect to setting, revising, or assessing compliance with NERC reliability standards should not be influenced by anti-competitive motivations.

Subject to the foregoing restrictions, participants in NERC activities may discuss:

• Reliability matters relating to the bulk power system, including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities.

• Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system.

• Proposed filings or other communications with state or federal regulatory authorities or other governmental entities.

• Matters relating to the internal governance, management and operation of NERC, such as nominations for vacant committee positions, budgeting and assessments, and employment matters; and procedural matters such as planning and scheduling meetings.


Public Announcements REMINDER FOR USE AT BEGINNING OF MEETINGS AND CONFERENCE CALLS THAT HAVE BEEN PUBLICLY NOTICED AND ARE OPEN TO THE PUBLIC Conference call version: Participants are reminded that this conference call is public. The access number 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: Participants are reminded that 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: Participants are reminded that 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.

August 10, 2010


NERC Participant Conduct Policy General Consistent with its Rules of Procedure, Bylaws, and other governing documents, NERC regularly collaborates with its members and other stakeholders to help further its mission to assure the effective and efficient reduction of risks to the reliability and security of the grid. Many NERC members and other bulk power system experts provide time and expertise to NERC, and the general public, by participating in NERC committees, subcommittees, task forces, working groups, and standard drafting teams, among other things. To ensure that NERC activities are conducted in a responsible, timely, and efficient manner, it is essential to maintain a professional and constructive work environment for all participants, including NERC staff; members of NERC committees, subcommittees, task forces, working groups, and standard drafting teams; as well as any observers of these groups. To that end, NERC has adopted the following Participant Conduct Policy (this “Policy”)for all participants engaged in NERC activities. Nothing in this Policy is intended to limit the powers of the NERC Board of Trustees or NERC management as set forth in NERC’s organizational documents, the NERC Rules of Procedure, or under applicable law. This Policy does not apply to the NERC Board of Trustees or the Member Representatives Committee.

Participant Conduct Policy All participants in NERC activities must conduct themselves in a professional manner at all times. This Policy includes in-person conduct and any communication, electronic or otherwise, made as a participant in NERC activities. Examples of unprofessional conduct include, but are not limited to, verbal altercations, use of abusive language, personal attacks or derogatory statements made against or directed at another participant, and frequent or patterned interruptions that disrupt the efficient conduct of a meeting or teleconference. Additionally, participants shall not use NERC activities for commercial purposes or for their own private purposes, including, but not limited to, advertising or promoting a specific product or service, announcements of a personal nature, sharing of files or attachments not directly relevant to the purpose of the NERC activity, and communication of personal views or opinions, unless those views are directly related to the purpose of the NERC activity. Unless authorized by an appropriate NERC officer, individuals participating in NERC activities are not authorized to speak on behalf of NERC or to indicate their views represent the views of NERC, and should provide such a disclaimer if identifying themselves as a participant in a NERC activity to the press, at speaking engagements, or through other public communications. Finally, participants shall not distribute work product developed during the course of NERC activities if that work product is deemed Confidential Information consistent with the NERC Rules of Procedure Section 1500. Participants also shall not distribute work product developed during the course of NERC activities if distribution is not permitted by NERC or the relevant committee chair or vice chair (e.g., an embargoed report), provided that NERC, or the committee chair or vice chair in consultation with NERC staff, may grant in writing a request by a participant to allow further distribution of the work product to one or more specified entities within its industry sector if deemed to be appropriate. Any participant that distributes

NERC Participant Conduct Policy 2

work product labeled “embargoed,” “do not release,” or “confidential” (or other similar labels) without written approval for such further distribution would be in violation of this Policy. Such participants would be subject to restrictions on participation, including permanent removal from participation on a NERC committee or other NERC activity.

Reasonable Restrictions on Participation If a participant does not comply with this Policy, certain reasonable restrictions on participation in NERC activities may be imposed as described below. If a NERC staff member, or committee chair or vice chair after consultation with NERC staff, determines, by his or her own observation or by complaint of another participant, that a participant’s behavior is disruptive to the orderly conduct of a meeting in progress or otherwise violates this Policy, the NERC staff member or committee chair or vice chair may remove the participant from a meeting. Removal by the NERC staff member or committee chair or vice chair is limited solely to the meeting in progress and does not extend to any future meeting. Before a participant may be asked to leave the meeting, the NERC staff member or committee chair or vice chair must first remind the participant of the obligation to conduct himself or herself in accordance with this Policy and provide an opportunity for the participant to comply. If a participant is requested to leave a meeting by a NERC staff member or committee chair or vice chair, the participant must cooperate fully with the request. Similarly, if a NERC staff member, or committee chair or vice chair after consultation with NERC staff, determines, by his or her own observation or by complaint of another participant, that a participant’s behavior is disruptive to the orderly conduct of a teleconference in progress or otherwise violates this Policy, the NERC staff member or committee chair or vice chair may request the participant to leave the teleconference. Removal by the NERC staff member or committee chair or vice chair is limited solely to the teleconference in progress and does not extend to any future teleconference. Before a participant may be asked to leave the teleconference, the NERC staff member or committee chair or vice chair must first remind the participant of the obligation to conduct himself or herself in accordance with this Policy and provide an opportunity for the participant to comply. If a participant is requested to leave a teleconference by a NERC staff member or committee chair or vice chair, the participant must cooperate fully with the request. Alternatively, the NERC staff member or committee chair or vice chair may choose to terminate the teleconference. At any time, a NERC officer, after consultation with NERC’s General Counsel, may impose a restriction on a participant from one or more future meetings or teleconferences, a restriction on the use of any NERC-administered listserv or other communication list, or such other restriction as may be reasonably necessary to maintain the orderly conduct of NERC activities. Before approving any such restriction, the NERC General Counsel must provide notice to the affected participant and an opportunity to submit a written objection to the proposed restriction no fewer than seven days from the date on which notice is provided. If approved, the restriction is binding on the participant, and NERC will notify the organization employing or contracting with the restricted participant. A restricted participant may request removal of the restriction by submitting a request in writing to the NERC General Counsel. The restriction will be removed at the reasonable discretion of the NERC General Counsel or a designee.

NERC Participant Conduct Policy 3

Upon the authorization of the NERC General Counsel, NERC may require any participant in any NERC activity to execute a written acknowledgement of this Policy and its terms and agree that continued participation in any NERC activity is subject to compliance with this Policy.

Guidelines for Use of NERC Email Lists NERC provides email lists, or “listservs,” to NERC stakeholder committees, groups, and teams to facilitate sharing information about NERC activities. It is the policy of NERC that all emails sent to NERC listservs be limited to topics that are directly relevant to the listserv group’s assigned scope of work. NERC reserves the right to apply administrative restrictions to any listserv or its participants, without advance notice, to ensure that the resource is used in accordance with this and other NERC policies. Prohibited activities include using NERC‐provided listservs for any price‐fixing, division of markets, and/or other anti‐competitive behavior. Recipients and participants on NERC listservs may not utilize NERC listservs for their own private purposes. This may include lobbying for or against pending balloted standards, announcements of a personal nature, sharing of files or attachments not directly relevant to the listserv group’s scope of responsibilities, or communication of personal views or opinions, unless those views are provided to advance the work of the listserv’s group. Any offensive, abusive, or obscene language or material shall not be sent across the NERC listservs. Any participant who has concerns about this Policy may contact NERC’s General Counsel. Version History

Version Date Revisions

1 February 6, 2019 Initial version

2 February 22, 2019 Clarified policy does not apply to Board or MRC Address participants speaking on behalf of NERC

Agenda Item 1b.i Real Time Operating Subcommittee Meeting

February 9, 2021

Real Time Operating Subcommittee Roster

Chair Chris Pilong Director of Dispatch

PJM Interconnection, L.L.C.

Vice Chair James E. Hartmann, Jr. Director, Control Room Operations

Electric Reliability Council of Texas Inc.

Tim Beach ** Director Reliability Coordination

California ISO/(RC West)

Kyle Russell Senior Manager, Market Forecasts & Integration

Independent Electricity System Operator

Richard McCall* Director, Environmental & Transmission Compliance

North Carolina Electric Membership Corp

Raj Thappetaobula Manager, Reliability Coordination and Engineering

Midcontinent ISO

Maxime Nadeau Manager – System Scheduling and Settlements

Hydro-Quebec

John R. Norden** Director, Operations

ISO New England, Inc.

Vince Ordax Director of Operations

Florida Reliability Coordination Council

Linwood Ross Manager, System Operations Engineering Carolinas

Duke Energy

Tim Reynolds Senior Reliability Engineer

Western Electricity Coordinating Council

Darren Wilkie** Manager Real-Time Operations

Alberta Electric System Operations

Steven C. Sanders* Operations & Transmission Advisor

Western Area Power Administration - UGPR

Lacy Skinner Assistant Chief System Operator

New York Independent System Operator

Asher Steed Manager System Operations

BC Hydro

Christopher Wakefield

Southeastern Reliability Coordinator Southern Company Services, Inc.

Bryan Wood Manager System Operations

Southwest Power Pool, Inc.

Terry Williams Manager Reliability Operations

Tennessee Valley Authority

Raj Venkat Manager RC Operations

Florida Reliability Coordination Council, Inc.

NERC Staff Darrell Moore Associate Director BPSA

North American Electric Reliability Corporation

Stephen Crutchfield Principal Technical Advisor and Coordinator for the RSTC


Bill Graham Principle BPSA Coordinator


Stephanie Lawrence Senior Administrative Assistant


Grandfathered members* Executive Committee members**

Agenda Item 1c Real Time Operating Subcommittee Meeting

February 9, 2021 Parliamentary Procedures

Based on Robert’s Rules of Order, Newly Revised, 1990 Edition 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.” Otherwise, this motion is debatable and subject to 2/3 majority approval.

Record each member’s vote on a Motion

Request a Roll Call Vote

No Takes precedence over main motion. No debate required, 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 cannot 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.

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. Revisions. Technically, revisions to the main motion are accomplished by the Amend procedure. However, immediately after making the motion, and before it is announced by the Chair, another member may ask that the motion be revised. If the original “motion -maker” agrees to the revision, then the revised motion will be the one debated. The original “seconder” need not be consulted, because the original “motion-maker” plus the “reviser” constitutes a motion and a second.

1

NERC RELIABILITY COORDINATOR AREAS Effective: December 3, 2019

1

1 AESO is currently providing their own Reliability Coordinator services consistent with Alberta legislation.

SPPW SPP

HQT ONT

ISONE NYISO PJM

SOCO

TVA VACAR-S

FRCC

ERCOT

MISO

Future

NBPC

SPRC

AESO

RC West

BCRC

Agenda Item 1dReal Time Operating Subcommittee Meeting

February 9, 2021

2

NERC RELIABILITY COORDINATOR DESKS Effective: December 3, 2019

CURRENT RELIABILITY

COORDINATOR

FUTURE RELIABILITY

COORDINATOR

COMMENT

HQT Same

ONT (IESO) Same

ISONE Same

NBPC Same

NYISO Same

PJM Same

MISO (Carmel, Eagan, Little Rock) Same

SPRC Same

VACAR−S Same

TVA Same

SOCO Same

FRCC Same

SPP/SPPW Same

ERCOT Same

AESO RC2 Same

RC West Same

BC Hydro Same


3

NERC BALANCING AUTHORITY TO RELIABILITY COORDINATOR MAPPING

December 3, 2019

This table indicates the Reliability Coordinators associated with each Balancing Authority within each Interconnection.

Current Reliability

Coordinator

Balancing Authority

Local Balancing Authority

Future Reliability

Coordinator

Regional Entity Expected Date For Change

HQT HQT NPCC

ISONE ISNE NPCC NBPC NBPC NPCC

NSPI NPCC NYISO NYIS NPCC ONT ONT NPCC PJM PJM RF/SERC

VACAR-S DUK SERC SCEG SERC SC SERC CPLW SERC YAD SERC CPLE SERC

TVA LGEE SERC TVA SERC AECI SERC

SOCO SOCO SERC SEPA SERC AEC SERC

FRCC FMPP SERC FPC (DEF) SERC FPL SERC GVL SERC HST SERC JEA SERC NSB SERC SEC SERC TAL SERC TEC SERC

MISO MISO RF/SERC/MRO MECS RF

4

Current Reliability

Coordinator

Balancing Authority


Future Reliability

Coordinator


CIN RF HE RF IPL RF DECO RF NIPS RF SIGE RF MIUP RF WEC RF CONS RF WPS RF BREC SERC AMIL SERC AMMO SERC CWLD SERC CWLP SERC SIPC SERC GridLiance Heartland

SERC

EES SERC CLEC SERC LAFA SERC LEPA SERC LAGN SERC SME SERC HMPL SERC ALTE MRO ALTW MRO MGE MRO UPPC MRO GRE MRO MEC MRO MP MRO MPW MRO NSP MRO OTP MRO SMP MRO DPC MRO

MHEB MRO

AESO3 AESO WECC

BCRC BC Hydro WECC

RC West BANC WECC CENACE WECC IID WECC


5

Current Reliability

Coordinator

Balancing Authority


Future Reliability

Coordinator


LAWP WECC TID WECC CAISO WECC GWA WECC AVA WECC BPAT WECC CHPD WECC DOPD WECC GCPD WECC IPCO WECC NWMT WECC PGE WECC PACW WECC PSEI WECC SCL WECC WWA WECC TPWR WECC PACE WECC AZPS WECC PNM WECC NEVP WECC SRP WECC GRID WECC AVRN WECC

SPRC SPC MRO

ERCOT ERCO Texas RE

SPPW TEPC WECC WACM WECC WALC WECC HGMA WECC PSCO WECC EPE WECC DEAA WECC GRIF WECC WAUW WECC

SPP SWPP MRO SPA MRO

- 1 -

Guideline for Approving Regional and Reliability Coordinator Reliability Plans The framework for approving Regional and Reliability Coordinator Reliability Plans Version 1

Approved by the Operating Committee: March 21, 2007

Prepared by the Operating Reliability Subcommittee

Agenda Item 3.a.i Real Time Operating Subcommittee Meeting

February 9, 2021

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Guideline for Approving Regional and Reliability Coordinator Reliability Plans

March 21, 2007 - 2 -

Introduction

The Regional Reliability Plan Guideline provides a framework for the Regional Reliability Organization to use when developing its regional reliability plan (RRP). This guideline document outlines the process to be followed by the Regional Reliability Organization or by a Reliability Coordinator for submitting its RRP or Reliability Coordinator reliability plan (RCP) to NERC for approval.

The Regional Reliability Organization will submit its RRP or the Reliability Coordinator will submit its RCP to NERC for review and acceptance. The NERC Operating Committee will review for acceptance the operating section of the RRP and the RCP and the NERC Planning Committee will review for acceptance the planning sections. This process for the standing committees will focus on the completeness, feasibility, and adequacy of the Regional Reliability Organization’s or Reliability Coordinator’s reliability plan.


Approved by Operating Committee March 22, 2007 - 3 -

Approval Process

Each Regional Reliability Organization or Reliability Coordination will submit its respective RRP or RCP to the Operating Committee’s Operating Reliability Subcommittee (ORS) for initial review and approval. The ORS shall follow the process as outlined below and as illustrated in the “Approval Process Flow Chart” section when reviewing a RRP or a RCP:

1. Regional Reliability Organization Review and Approval of RRP or RCP. TheRegional Reliability Organization (RRO) shall review and approve its Regional ReliabilityPlan before it is submitted to NERC for review and approval. The Reliability Coordinatorshall submit its Reliability Plan to all Regional Reliability Organizations within which itoperates for their respective review and approval before such plan is submitted to NERCfor review and approval.

2. ORS Review. ORS endorsement of the RRP or RCP is based upon its assessment of theRegional Reliability Organization’s or the Reliability Coordinator’s ability to meet NERCreliability standards. To aid in this assessment, the ORS may request an operationalreview (reliability readiness evaluation) of the Reliability Coordinator.

3. Reliability Readiness Evaluation. At the request of the ORS, NERC will conduct areliability readiness evaluation of an existing or prospective Reliability Coordinator. Thereliability readiness evaluation may contain recommendations which the RC mustimplement prior to the Reliability Coordinator beginning operations. In this instance theReliability Coordinator will develop a mitigation plan that addresses therecommendations. The reliability readiness evaluation team will present the evaluationand mitigation plan, if any, to the ORS.

4. ORS Endorsement of RRP or RCP. Following its review of the RRP or RCP (and thereliability readiness evaluation), the ORS will decide whether to endorse the RRP or RCPfor presentation to the Operating Committee. If the ORS cannot endorse the RRP or RCP,the subcommittee will indicate its objections to the Regional Reliability Organization orthe Reliability Coordinator.

5. Operating Committee Approval of RRP or RCP. The ORS will present itsendorsement of the RRP or RCP to the Operating Committee for action.

6. Approval of Minor Revisions to a RRP or RCP. The Operating Committee delegatesthe approval of minor revisions to a RRP or RCP (e.g., reliability plan “footprint” change)to the ORS.

7. Posting of an Approved RRP or RCP. NERC shall post approved Regional ReliabilityPlans and Reliability Coordinator Reliability Plans on its Web site.

8. Access to NERC Reliability Tools. Reliability Coordinators are required to sign theReliability Coordinator Standards of Conduct and the Confidentiality Agreement forElectric System Operating Reliability Data before NERC can grant access to the ReliabilityCoordinator reliability tools. Furthermore, NERC shall not grant access to some reliabilitytools (e.g., the Interchange Distribution Calculator), with the exception of granting accessto the training environment of such tools, until the Reliability Coordinator receivesapproval to begin operation.


Approved by Operating Committee March 22, 2007 - 4 -

9. RRP or RCP Periodic Review. The Regional Reliability Organization or ReliabilityCoordinator shall review its respective RRP or RCP at least every three years and notify theORS of the results of such review.


Approved by Operating Committee March 22, 2007 Revised January 14, 2021

- 5 -

Approval Process Flow Chart

Following RRO Review and Approval the RC/Prospective RCSubmits Reliability Plan to ORS

RTOSEndorsesApproval

RTOSReviews Plan

RTOSPresents plan to RSTC Recommends Approval

With Starup Predicated on Evaluation Results

Satisfactory to RTOS

RSTC Approves Plan

Yes

NERCProvides Access

toIDC, SDX, RCIS

RC/Prospective RC

Re-Submits Reliability Plan to

RTOS

RTOSSpecifies Changes

NoRC/PRCRevises Plan

RSTCSpecifies Changes

No

NERCPerforms

Evaluation

RTOSReviews Results

EvaluationOK ?

RTOSApproves

RC Start up

RTOSInformsRSTC

Yes

RTOSSpecifies Mitigating Measures

No

RC/PRCImplementsMitigating Measures

RC/PRCPresents

CompletedMitigating MeasuresTo ORS

RTOSAccepts

SecondEvaluationRequired?

Yes

No

NoYes

Yes

If EvaluationIs Needed

The Reliability and Security Technical Committee (RSTC) and Real Time Operating Subcommittee (RTOS) shall follow the process flow diagram detailed below when reviewing a Regional Reliability Organization Reliability Plan or a Reliability Coordinator Reliability Plan.

December 3, 2020 DRAFT for Real Time Operating Subcommittee (RTOS) Endorsement

CLEAN

Northeast Power Coordinating Council, Inc. Regional Reliability Plan

Version 2.0

Approved by the NPCC Task Force on Coordination of Operations December 3, 2020

NPCC Regional Reliability Plan-Month XX, 2020

Page 2 of 32

NPCC System Operations Managers Working Group (CO-8): Ioan Agavriloai Independent Electricity System Operator Gaëtan Benoit New Brunswick Power Corporation Caroline Bouchard Hydro-Québec TransÉnergie Steven Gould ISO New England, Inc. Andrey Oks Northeast Power Coordinating Council, Inc. Jon Sawyer New York ISO


Page 3 of 32

Table of Contents

EXECUTIVE SUMMARY .............................................................................................................5

RELIABILITY PLAN ELEMENTS..............................................................................................6 1. TERMS ................................................................................................................................................6 2. NPCC RELIABILITY COORDINATORS .................................................................................................6

2.1. Responsibilities ........................................................................................................................7 2.2. Standards of Conduct and Confidentiality ...............................................................................8 2.3. Authorizations .........................................................................................................................8 2.4. Delegation of Tasks .................................................................................................................8

3. NORMAL OPERATIONS .......................................................................................................................9 3.1. Next Day and Current Day Operations ....................................................................................9

4. EMERGENCY OPERATIONS ............................................................................................................... 16 4.1. Precedence Over Commercial Operations ............................................................................. 16 4.2. Action that would Lead to an Emergency Condition ............................................................. 16 4.3. Exercising Specific Authority to Prevent and Mitigate Emergencies .................................... 16 4.4. Exercising specific Authority for Load Shedding .................................................................. 17 4.5. Communication and Coordination ......................................................................................... 17 4.6. Emergency Operations Criteria ............................................................................................. 18 4.7. Plans for Loss of Primary Control Center Functionality ....................................................... 22

5. SYSTEM RESTORATION .................................................................................................................... 22 5.1. Reliability Coordinator Restoration Plan ............................................................................... 22 5.2. Reliability Coordinator is the Primary Contact...................................................................... 22 5.3. Reestablishing Normal Operations ........................................................................................ 23 5.4. Priority to Supply Power to Nuclear Plants ........................................................................... 23 5.5. Communication and Coordination ......................................................................................... 23

6. RELIABILITY MONITORING AND COORDINATION ............................................................................. 24 6.1. Coordination Agreements ...................................................................................................... 24 6.2. Data Requirements................................................................................................................. 24 6.3. Data Exchange ....................................................................................................................... 24 6.4. Coordination and Monitoring ................................................................................................ 25 6.5. NPCC Conference Calls ........................................................................................................ 26

7. RELIABILITY APPLICATIONS ............................................................................................................. 26 7.1. Analysis Tools ....................................................................................................................... 26 7.2. Communication Facilities ...................................................................................................... 26 7.3. Real Time Monitoring ........................................................................................................... 27

8. STAFFING AND TRAINING ................................................................................................................. 27 8.1. Reliability Coordinator Staffing Requirements ..................................................................... 27 8.2. Certification ........................................................................................................................... 27 8.3. Staff Expertise ....................................................................................................................... 27 8.4. Training ................................................................................................................................. 27

9. NPCC OPERATING CONSIDERATIONS .............................................................................................. 28 9.1. ISO-NE .................................................................................................................................. 28 9.2. NYISO ................................................................................................................................... 28 9.3. The Independent Electricity System Operator (IESO)........................................................... 28 9.4. System Control Department (Direction Contrôle des mouvements d’énergie), Hydro-Québec TransÉnergie ................................................................................................................................... 29 9.5. New Brunswick Power – System Operator (NBP-SO) .......................................................... 29 9.6. Descriptions of Specific Operating Considerations ............................................................... 29

10. PLAN UPDATES AND CHANGES ........................................................................................................ 30


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Version History

Version Date Action Change Tracking (New, Errata or Revisions)

1 New 1.1 June 5, 2013 1. Editorial changes and reference updates. Removal

of the detailed Appendices and explicit compliance language.

Revisions

1.2 June 1, 2016 1. Editorial changes and reference updates, including: • references to “Directives” were changed to

“Operating Instructions” • references to “violations” were changed to

“exceedances” • Reference to ISN was changed to EInet • references to “CPS” were changed to “BAAL”

Revisions

2.0 Month, date, 2020

1. Added content specified in the NERC Reliability Coordinator Reliability Plan Reference Document, including: • Version History • List of BAs and TOPs in each RC’s footprint • Pseudo-ties • Congestion management • Plan updates and changes provisions

2. Editorial changes and reference updates, including: • Reference to the applicable registration

sections of NERC ROP • Eliminated/replaced references to the

“unknown operating state” with “Real-time Assessment”

• Updates to the applicable functional entities • Reference to ISN was changed to EIDSN • Updated SPS references with RAS • Eliminating section referencing “Beyond Real

Time” as it is outside of the Regional of NERC’s RC Reliability Plan scope

3. Changes conforming with Directory revisions, including: • Directory 5 - eliminating processes and

implementation of Regional Reserve, • Directory 8 – eliminating processes for

establishing, reviewing and maintaining Regional Restoration Plan.

Revisions


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EXECUTIVE SUMMARY The Northeast Power Coordinating Council (NPCC) Reliability Plan describes the procedures, practices and requirements implemented to facilitate the reliable operation of the Bulk Power System (BPS) within the NPCC Region.

The NPCC Reliability Plan outlines the following objectives:

• Identifies the regional entities that are registered with NERC in accordance with the Section 500 – “Organization Registration and Certification” and Appendices 5A and 5B of the FERC-approved NERC Rules of Procedure who are responsible for performing specified reliability functions to which requirements of mandatory NERC Reliability Standards are applicable and summarizes the operating functions that will be performed by those registered entities.

• Identifies the essential industry practices to promote effective Wide Area reliability among the Reliability Coordinators (RC) within the NPCC Region: the Ontario Independent Electricity System Operator (IESO), the New York ISO (NYISO), ISO New England, Inc. (ISO-NE), New Brunswick Power SO (NBP-SO) and Hydro-Québec TransÉnergie.

• Identifies the Wide Area view that provides for reliability monitoring and assessment among the Reliability Coordinators.

• Documents the procedures and tools necessary for NPCC’s Reliability Coordinators to monitor and direct the real-time operation of their RC Area in coordination with their neighboring Reliability Coordinators.

• Documents the Reliability Coordinators’ authority to direct other responsible entities to take corrective actions to maintain the reliability and integrity of their respective RC Areas.

The NPCC Reliability Plan identifies the coordination and monitoring in both the current day and day ahead timeframes. The plan describes procedures for normal and emergency states of operation and presents the processes for the sharing and dissemination of information utilizing NPCC procedures, conference calls and NERC communication tools.

The NPCC Reliability Plan identifies the procedures to maintain reliable operations through coordinated analysis and Real-time Assessments during emergencies caused by abnormal voltage conditions or transmission loading, unanticipated parallel flow, operating reserve deficiencies, and frequency deviations. The NPCC Reliability Plan also provides an overview of the RC plans and procedures for system restoration and training.

http://www.nerc.com/AboutNERC/Pages/Rules-of-Procedure.aspx


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RELIABILITY PLAN ELEMENTS

1. Terms Bolded expressions used in the NPCC Reliability Plan have the meanings ascribed thereto in the “Glossary of Terms Used in NERC Reliability Standards” and the “NPCC Glossary of Terms”.

2. NPCC Reliability Coordinators The NPCC Reliability Coordinators along with their Transmission Operators and Balancing Authorities for the Eastern and Québec Interconnections are:

• Independent Electricity System Operator (IESO), for the province of Ontario (known as the Ontario Area); o BAs: IESO o TOPs: IESO, Hydro One Networks, Inc.

• New York Independent System Operator (NYISO), for the state of New York (known as the New York Area); o BAs: NYISO o TOPs: NYISO, Consolidated Edison Co of NY, Inc, Long Island Power

Authority, Niagara Mohawk Power Corporation, New York State Electric & Gas, Orange and Rockland Utilities, Inc., Rochester Gas and Electric, Central Hudson Gas & Electric Corporation, Alcoa Power Generating Inc.-Long Sault Division

• Independent System Operator of New England (ISO-NE), for the New England six states: MA, CT, RI, NH, VT, and all of ME except for Maine Public Service Company and Eastern Maine Electric Cooperative (known as the New England Area); o BAs: ISO-NE o TOPs: ISO-NE, Central Maine Power Company, Eversource Energy

Service Company, New England Power Company, Vermont Transco LLC

• New Brunswick Power – System Operator (NBP-SO), for New Brunswick Power, Nova Scotia Power Incorporated, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative are not part of the Bulk Power System. o BAs: NBP, NSPI o TOPs: NBP, NSPI

• System Control and Operations Department (Direction Contrôle et exploitation du réseau), Hydro-Québec TransÉnergie (HQT) for the Québec Interconnection and the transmission lines between Churchill Falls Generating Station (Labrador) and HQT system (known as the Québec Area). o BAs: HQT


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o TOPs: HQT To maintain the operational reliability of the NPCC Region, the NPCC Reliability Coordinators carry out the following tasks:

• Plan for next-day operations and analyze current day operating conditions, which includes reliability analyses such as pre- and post-contingency thermal monitoring, operating reserves, area reserves, reactive reserves, voltage limits, stability, etc., that may identify operating conditions for which special procedures may be needed;

• Implement procedures to mitigate System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances on the transmission system. Regardless of the process, the Reliability Coordinator is required to ensure that the transmission system is returned to within Interconnection Reliability Operating Limits as soon as possible, but no longer than 30 minutes.

• Monitor the Wide Area and observe the Interconnection Reliability Operating Limits. Wide Area monitoring is described as the ability to monitor the complete Reliability Coordinator Area, including critical flow, Pseudo-Tie flow (if applicable) and status information from adjacent Reliability Coordinator Areas as determined by detailed system studies.

2.1. Responsibilities

2.1.1. Reliable Operation The Reliability Coordinator is responsible for the reliable operation of its Reliability Coordinator Area in accordance with NPCC and NERC Standards. The Reliability Coordinator will assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundaries.

2.1.2. Wide Area View The Reliability Coordinator is responsible for having the Wide Area view, the operating tools, processes and procedures, including the authority, to prevent or mitigate emergency operating situations in both next-day analysis and during real-time conditions.

2.1.3. Authority The Reliability Coordinator has clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, and Distribution Providers within its Reliability Coordinator Area to preserve the integrity and reliability of the Bulk Power System (BPS).

2.1.4. Delegation


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If a Reliability Coordinator delegates tasks to others, the Reliability Coordinator retains its responsibilities for complying with NERC and regional standards.

All responsibilities for complying with NERC and regional standards applicable to Reliability Coordinators remain with the Reliability Coordinator.

2.2. Standards of Conduct and Confidentiality

2.2.1. Standards of Conduct The NPCC Reliability Coordinator adheres to the NERC Confidentiality Agreement for “Electric System Reliability Data” and the NPCC Code of Conduct

2.3. Authorizations

2.3.1. Serving the interests of the NPCC Reliability Coordinator Areas

The Reliability Coordinator acts in the interests of reliability first for the overall Reliability Coordinator Area and the Interconnection before the interests of any other entity.

2.3.2. Compliance with Reliability Coordinator Operating Instructions

Transmission Operators, Balancing Authorities, Generator Operators, and Distribution Providers comply with Reliability Coordinator Operating Instructions unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, these entities immediately inform the Reliability Coordinator of the inability to perform the Operating Instruction so that the Reliability Coordinator may implement alternate remedial actions.

2.4. Delegation of Tasks

2.4.1. Delegating Tasks

The Reliability Coordinator may delegate tasks to other entities, if this delegation is accompanied by formal operating agreements, with each entity to which tasks are delegated. The Reliability Coordinator verifies that all delegated tasks are understood, communicated, and addressed within its Reliability Coordinator Area. The Reliability Coordinator lists within its reliability plan all entities to which the Reliability Coordinator has delegated tasks. Reliability Coordinators that delegate tasks consist of the following:

• ISO-NE: None


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• NYISO: None

• IESO: None

• NBP-SO: None

• HQT: None

Each Transmission Operator, Balancing Authority, and Reliability Coordinator staffs all operating positions that meet both of the following criteria with personnel that are NERC certified for the applicable functions:

(i) Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected BPS.

(ii) Positions directly responsible for complying with NERC standards.

3. Normal Operations

3.1. Next Day and Current Day Operations

3.1.1. Common Tasks to Next Day and Current Day Operations

3.1.1.1. Assess Contingency Situations

The Reliability Coordinator conducts Operational Planning Analysis and Real-time Assessments based on thermal, voltage and stability limits to coordinate current day and next day operations within applicable SOL and IROL. The Wide Area view of the Reliability Coordinator is modeled to meet the requirements of coordinated operations.

3.1.1.2. Determine IROL

The Reliability Coordinator determines an IROL based on local, Regional and inter-Regional studies. The Reliability Coordinator must recognize that an IROL exceedance can be created during multiple, normally non-critical outage conditions and, as such, the Reliability Coordinator must be knowledgeable of events that could lead to such an occurrence. The Reliability Coordinator is responsible for disseminating this information within its Reliability Coordinator Area and to neighboring Reliability Coordinators.

3.1.1.3. Ensure that each Reliability Coordinator Area Does Not Burden Adjacent Reliability Coordinator Area


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The Reliability Coordinator operates to prevent the likelihood that a disturbance, action, or non-action in its Reliability Coordinator Area will result in a SOL or IROL exceedance in another Area of the Interconnection. In instances where the derived operating limits differ from one Area to another, the Reliability Coordinators operates the BPS to the most limiting parameter.

Each Reliability Coordinator monitors parallel flows which can place an unacceptable or undue burden on an adjacent Reliability Coordinator Area.

3.1.1.4. Transfer Capability Coordination

The Reliability Coordinator makes known to Transmission Service Providers within its Reliability Coordinator Area, SOLs or IROLs within its Wide Area view. The TSP respects these SOLs or IROLs in the determination of transfer capabilities, in accordance with filed tariffs and/or regional TTC/ATC calculation processes.

3.1.1.5. Communicate Effectively

The Reliability Coordinator issues Operating Instructions in a clear, concise and definitive manner.

3.1.1.6. Maintain Flows Within Limits

The Reliability Coordinator identifies the cause of the potential or actual SOL or IROL exceedance and initiates the control action or emergency procedure to relieve the potential or actual SOL or IROL exceedance consistent with NERC Reliability Standards.

The Reliability Coordinator evaluates actions taken to address an IROL or SOL exceedance and, if the actions taken are not appropriate or sufficient, direct actions required to return the system to within limits.

3.1.1.7. Maintain a Wide Area View

Each Reliability Coordinator monitors all BPS facilities, which may include sub-transmission information, within its Reliability Coordinator Area and adjacent Reliability Coordinator Areas via the Eastern Interconnection Data Sharing Network (EIDSN), as necessary to ensure that, at any time, regardless of prior planned or unplanned events, the Reliability Coordinator is able to determine any potential SOL


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and IROL exceedances within its Reliability Coordinator Area.

Each Reliability Coordinator notifies specific neighboring RCs when an element listed in the NPCC Facilities Notification List1 is scheduled to be removed from service or has been removed from service due to a forced outage event.

Each Reliability Coordinator is aware of the current status of all critical facilities whose failure, degradation or disconnection could result in an SOL or IROL exceedance. Reliability Coordinators are aware of the status of any facilities that may be required to assist area restoration objectives.

3.1.1.8. Inter-Area/Inter-Regional Coordination

Reliability Coordinators are responsible for addressing inter-Area or inter-Regional operational concerns by coordinating their actions with other Reliability Coordinators from the NPCC Region and other Regions. This includes both foreseen and unforeseen events. Reliability Coordinators are responsible for taking immediate actions to contain an operating problem and to request or provide assistance from or to other Reliability Coordinators.

The Reliability Coordinator coordinates with other Reliability Coordinators and other responsible entities as needed to develop and implement action plans to mitigate potential or actual SOL, IROL, BAAL exceedances or DCS violations. This includes coordination of pending generation and transmission maintenance outages in both the current-day and next-day timeframes. It also includes coordination of any actions, including emergency assistance, required to mitigate any operational concerns.

When a Reliability Coordinator is aware of an operational concern, such as declining voltages, excessive reactive flows, or an IROL exceedance, in a neighboring Reliability Coordinator Area, it contacts the Reliability Coordinator in whose Area the operational concern was observed. The two Reliability Coordinators coordinate any actions, including emergency assistance, required to mitigate the operational concern.

1 NPCC Regional Reliability Reference Directory # 1 - Design and Operation of the Bulk Power System, Appendix F – Procedure for Operational Planning Coordination, Section 4.2 – “The Facilities Notification List is developed by each RC Area and specifies all facilities that, if removed from service, may have a significant, direct or indirect impact on another RC Area’s transfer capability. The cause of such impact might include stability, voltage, and/or thermal considerations.”


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3.1.2. Next-Day Operations

3.1.2.1. Reliability Analysis and System Studies

The Reliability Coordinator conducts next-day Operational Planning Analysis for its Reliability Coordinator Area.

3.1.2.1.1. Contingency Analysis

The Reliability Coordinator conducts contingency analysis studies to identify potential interface and other SOL and IROL exceedances.

3.1.2.1.2. Parallel Flows

Each Reliability Coordinator monitors parallel flows which place an unacceptable or undue burden on an adjacent Reliability Coordinator Area.

3.1.2.2. Information Sharing

Each responsible entity in the Reliability Coordinator Area provides to its Reliability Coordinator all information required for system studies, such as critical facility status, load, generation, Operating Reserve projections and known interchange transactions.

3.1.2.3. Action Plan Development

The Reliability Coordinator, in conjunction with its responsible entities, develops action plans that address operational concerns by reconfiguring the transmission system, re-dispatching generation, reducing or curtailing interchange transactions, or reducing firm load to return the transmission loading to within acceptable SOL and IROL.

3.1.2.4. Sharing of Study Results

When conditions warrant or upon request, the Reliability Coordinator shares the results of its system studies with responsible entities within its Reliability Coordinator Area or with other Reliability Coordinators.

When required, the Reliability Coordinator initiates a conference call or other appropriate communications to address the results of its reliability analyses.

3.1.2.5. Issuing Notifications


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If after applying all possible mitigation action plans, the study results indicate potential SOL or IROL exceedances, the Reliability Coordinator issues the appropriate notifications and directs its responsible entities to take the necessary actions to address the potential SOL or IROL exceedance.

3.1.2.6. Compliance with Reliability Coordinator Operating Instructions

All responsible entities comply with the Operating Instructions of their Reliability Coordinator based on the next day assessments in the same manner in which they would comply during real time operating events.

3.1.3. Current Day Operations

3.1.3.1. Status of Facilities

The Reliability Coordinator must be aware of the status of all facilities whose failure, degradation or disconnection could result in an SOL or IROL exceedance. Reliability Coordinators must also be aware of the status of any facilities that may be required to assist Area restoration objectives.

3.1.3.2. Situational Awareness

The Reliability Coordinator maintains awareness of operating conditions within its Reliability Coordinator Area and includes this information in its Real-time Assessment, including but not limited to the following, where applicable:

• Current status of the BPS, including, the status of automatic voltage regulators (AVR) and special protection systems (SPS) / Remedial Action Schemes (RAS).

• Current pre-contingency and post-contingency element conditions (voltage, thermal, or stability).

• Operating Reserve. • Reactive Reserves. • Capacity and energy adequacy conditions. • Current ACE for all its Balancing Authorities. • Area congestion management or TLR procedures in

effect. • Planned generation dispatches. • Planned transmission or generation outages • Contingency events.


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3.1.3.3. Interchange Transaction Monitoring

The Reliability Coordinator monitors interchange.

3.1.3.3.1. Interchange Transaction Information

The Reliability Coordinator is aware of all interchange transactions that wheel-through, source, or sink in its Reliability Coordinator Area.

3.1.3.3.2. Pending Interchange Schedules to Identify Potential Flow Impacts

As portions of the transmission system approach or exceed SOLs or IROLs, the Reliability Coordinator works with its responsible entities to evaluate and assess any additional Interchange Schedules that would exceed those limits. If the potential or actual SOL or IROL exceedance cannot be avoided through proactive intervention, the Reliability Coordinator initiates control actions or emergency procedures to relieve the exceedance. All resources, including the shedding of firm load, are available to the Reliability Coordinator to address a potential or actual SOL or IROL exceedance.

3.1.3.4. Time Error Correction (TEC) and Geomagnetic Disturbance Notification

Each Reliability Coordinator communicates and implements start and end times for time error corrections to the relevant responsible entities within its Reliability Coordinator Area, in accordance with the NERC Time Monitoring Reference Document.

NPCC contracts with the Solar Terrestrial Dispatch (STD) for a solar notification and communication system used by the five Reliability Coordinators, the Geomagnetic Storm Mitigation System (GSMS). An active communications software package installed on the system operator’s console provides each of the NPCC RCs with geomagnetic storm alerts and the status of solar activity. Upon receipt of a geomagnetic storm alert of Kp = 6 or higher, the GSMS simultaneously provides:

• visual and / or audible alarms; • a main screen providing the system operator with all

information currently known about possible solar activity; and


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• a dialog box permitting instantaneous communication among all NPCC Reliability Coordinators of any observed solar magnetic phenomenon.

Complementing the notification system, NPCC also established its Document C-15, “Procedures for Geomagnetic Disturbances Which Affect Electric Power Systems,” establishing protective measures which can be taken to minimize the vulnerability of the system to solar phenomenon. After reviewing the available data provided by the GSMS, the Reliability Coordinator may choose to enact one or more of the actions presented in Document C-15.”

3.1.3.5. System frequency and resolution of significant frequency errors, deviations and real-time trends.

The Reliability Coordinator monitors system frequency and its Balancing Authorities’ performance and directs any necessary re-balancing to return to BAAL and DCS compliance. The Transmission Operators and Balancing Authorities utilizes all resources, including the shedding of firm load, as directed by its Reliability Coordinator to relieve the emergent condition.

The Reliability Coordinator identifies sources of large Area Control Errors that may be contributing to Frequency Error, Time Error, or Inadvertent Interchange and discusses corrective actions with the appropriate Balancing Authority. If a sustained and unexplained Frequency Error is observed the Reliability Coordinator may initiate a NERC hotline call to discuss the Frequency with other Reliability Coordinators.

3.1.3.6. Monitoring of Special Protection Systems (SPS)/Remedial Action Schemes (RAS)

Whenever an SPS/RAS that may have an inter-Balancing Authority, inter-Transmission Operator, or inter-Reliability Coordinator Area impact (e.g., could potentially affect transmission flows resulting in a SOL or IROL exceedance) is armed, the Reliability Coordinators are aware of the impact of the operation of that SPS/RAS on inter-area flows. The Transmission Operator immediately informs the Reliability Coordinator of the status of the SPS/RAS including any degradation or potential failure to operate as expected.

3.1.3.7. Congestion management


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The RCs utilize security constrained dispatch to provide a secured solution for the internal transmission system, including generator dispatch and transaction scheduling.

RCs have a number of control actions available in order to manage congestion on internal and external (i.e. shared) constraints; some or all of these control actions may be used as applicable to manage congestion. These control actions include adjusting phase angle regulators, arming SPS/RAS, suspending or decreasing inadvertent payback, recalling outages, adjusting internal generation and dispatchable load through re-dispatch of resources, curtailing import/export transactions.

Additionally, where applicable, for external constraints management control actions include using the NERC transmission loading relief (TLR) procedure.

3.1.3.8. Congestion management agreements

Neighboring RCs within NPCC have agreements that address coordinated transaction scheduling and congestions management protocols. The list of the agreements can be found in the applicable coordination agreements, as specified in the Appendix A - Agreements with external entities.

4. Emergency Operations Emergency Operations Plans - Each Reliability Coordinator shall have a comprehensive Operating Plan to prepare for and mitigate Operating Emergencies on the Bulk Power System. The Operating Plan may consist of numerous procedures or processes. The purpose of an Emergency Operations Plan is to identify the RC, BA, and TOP roles, responsibilities and processes to prepare for and mitigate Operating Emergencies.

4.1. Precedence Over Commercial Operations

The integrity and reliability of the BPS is of paramount importance and takes precedence over the interest of any other entity.

4.2. Action that would Lead to an Emergency Condition

Reliability Coordinators and Transmission Operators, Generator Operators and Balancing Authorities do not take any action, or refrain from taking any action, that would, knowingly lead to an emergency condition within their Area or a neighboring Area.

4.3. Exercising Specific Authority to Prevent and Mitigate Emergencies


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Reliability Coordinators and Balancing Authorities and Transmission Operators have the responsibility and decision-making authority for maintaining the reliability of the BPS and exercise their specific authority to prevent and mitigate capacity and energy emergencies.

4.4. Exercising specific Authority for Load Shedding

The Reliability Coordinator has clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, , and Distribution Providers within its Reliability Coordinator Area to preserve the integrity and reliability of the BPS.

A Balancing Authority and Transmission Operator operating with insufficient generation or transmission capacity has the capability and authority to shed load.

4.5. Communication and Coordination

4.5.1. Effective Communication

Effective communication is critical during an emergency or as an emergency situation evolves. In order to mitigate the consequences of the event, NPCC Reliability Coordinators issue Operating Instructions in a clear, concise and definitive manner.

4.5.2. Notification of Potential Problems/Emergency

An NPCC Reliability Coordinator who foresees a transmission problem (such as an SOL or IROL exceedance, loss of reactive reserves, any emergency operating conditions, etc.) within its Reliability Coordinator Area notifies all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area, and all impacted Reliability Coordinators within the Interconnection.

4.5.3. Disseminating/Sharing Information

NPCC Reliability Coordinators use the NERC Hotline to disseminate information and exercise coordination with other Reliability Coordinators. Appropriate information is then disseminated to individual Balancing Authorities and Transmission Operators within their Reliability Coordinator Area.

4.5.4. NERC Hotline

For emergency situations that involve or affect the BPS, or when time is of the essence in the recognition, prevention, mitigation or


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resolution of the emergency, Reliability Coordinators may employ the NERC Hotline.

4.5.5. NERC RCIS

NPCC Reliability Coordinators may use the RCIS or other methods to provide notification of potential or actual emergency conditions. Such notifications include information regarding abnormal system conditions, which have the potential to burden neighboring Reliability Coordinators Areas such as:

• Extreme weather conditions that are likely to adversely impact the reliability of the BPS;

• Energy Emergency Alert; • Request for emergency energy assistance; • Major forced transmission and generation outages that

have, or are likely to have, an adverse impact on the reliability of the BPS;

• Abnormal voltage and frequency conditions.

4.5.5.1. NPCC Emergency Preparedness Conference Calls

To quickly exchange information about the current status of the BPS, to facilitate inter-Area emergency assistance, or to evaluate a physical threat to the systems, the Reliability Coordinators in NPCC may initiate an "NPCC Emergency Preparedness Conference Call." It may include representatives from PJM and MISO, as necessary.

4.5.6. Communication During Extended Emergencies

During extended emergencies, NPCC Reliability Coordinators provide effective, timely and accurate information to key entities such as media, government and regulatory bodies to facilitate public awareness and cooperation.

4.5.7. Energy Emergency Alerts

A Reliability Coordinator that is forecasting a potential, or experiencing an actual Energy Emergency within its Reliability Coordinator Area initiates an Energy Emergency Alert via the RCIS.

4.6. Emergency Operations Criteria

4.6.1. Disconnecting Facilities


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NPCC Transmission Operators and Generator Operator notify and coordinate with their Reliability Coordinator and Balancing Authority, as applicable and adjacent Transmission Operator before removing BPS facilities from service if removing those facilities would burden a neighboring Area.

For a generator outage, the Generator Operator notifies and coordinates with the Transmission Operator and Balancing Authority. The Transmission Operator and Balancing Authority notifies the Reliability Coordinator and other affected Transmission Operators and coordinates the impact of removing the BPS facility.

For a transmission facility, the Transmission Operator notifies and coordinates with its Reliability Coordinator. The Transmission Operator notifies other affected Transmission Operators and coordinates the impact of removing the BPS facility.

When time does not permit such notifications and coordination, or when immediate action is required to prevent a hazard to the public, lengthy customer service interruption, or damage to facilities, the Generator Operator notifies the Transmission Operator and Balancing Authority and the Transmission Operator notifies its Reliability Coordinator and adjacent Transmission Operators, at the earliest possible time.

The NPCC Reliability Coordinators maintain the NPCC list of "Facilities for Notification" that, if removed from service, may directly or indirectly burden a neighboring Transmission Operator.

4.6.2. Operating Within Limits

The Reliability Coordinator makes available to its operators a comprehensive set of operating limits for both normal and emergency conditions, including clear instructions describing the circumstances when these limits are to be used.

Where inter-Area reliability is affected, the Reliability Coordinator establishes limits and operates so that the contingencies can be withstood without adversely affecting other Areas. During emergencies, the Reliability Coordinator is required to operate within the applicable emergency System Operating Limits (SOL) and Interconnection Reliability Operating Limits (IROL). The Reliability Coordinator is required to implement emergency measures, including shedding of firm load, to maintain the operation of the power system within the applicable emergency limits.


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In instances where there is a difference in derived limits, the Reliability Coordinator operates the BPS to the most limiting parameter.

The Reliability Coordinators and Transmission Operators have sufficient real time information and analysis tools to determine potential SOL or IROL exceedances. This analysis is conducted in all operating timeframes. The Reliability Coordinator uses the results of these analyses to determine the causes of the exceedances and identify mitigating actions.

Each Reliability Coordinator identifies the cause of any potential or actual SOL or IROL exceedances. The Reliability Coordinator initiates the control action or emergency procedure to relieve the potential or actual IROL exceedance without delay, and no longer than 30 minutes. The Reliability Coordinator is able to utilize all resources, including load shedding, to address an IROL exceedance.

When an SOL or IROL exceedance is imminent, Reliability Coordinators must be aware that Transmission Loading Relief (TLR) procedures may not be able to address the exceedance in a timely fashion. In such circumstances the Reliability Coordinators have the authority and obligation to immediately direct their Transmission Operators, Generation Operators and Balancing Authorities to re-dispatch generation, reconfigure transmission, manage interchange transactions, or reduce system demand which may include shedding of firm load. These actions are used in conjunction with the TLR procedure to restore the system to normal state. The Reliability Coordinator coordinates these emergency control actions with other Reliability Coordinators as needed.

4.6.3. Frequency Control

The Reliability Coordinator identifies sources of large Area Control Error that may be contributing to frequency error, time error, or inadvertent interchange and discusses corrective actions with the appropriate Balancing Authority. If a Frequency Error, Time Error, or inadvertent problem occurs, the Reliability Coordinator initiates a NERC hotline call to discuss the frequency error, time error, or inadvertent interchange with other Reliability Coordinators, as appropriate. The Reliability Coordinator directs its Balancing Authorities to comply with BAAL and DCS.

During a system emergency, the Reliability Coordinator complies with NERC BAL Standards. The Reliability Coordinator does not rely on the frequency bias of the other Transmission Operators, Generation Operators and Balancing Authorities to provide energy during the emergency because doing so reduces the


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Interconnection’s ability to recover its frequency following additional generator failures.

If the Reliability Coordinator determines that Balancing Authorities within its Area cannot comply with the NERC BAL Standards, then it declares an Energy Emergency and implement remedies such as requesting assistance from other Reliability Coordinators, or implementing load reduction through public appeals, voltage reductions, curtailing interruptible loads and shedding firm load to return ACE to acceptable BAAL and DCS criteria.

4.6.4. Reactive Power Balance and Voltage Control

When an Area is experiencing abnormal voltage conditions, its Reliability Coordinator takes action to restore the reactive power balance. The Reliability Coordinator implements corrective control actions, which include requesting emergency assistance. If these actions are still not adequate to mitigate the reactive power imbalance then the Reliability Coordinator takes all necessary steps to relieve the abnormal voltage conditions, including firm load shedding.

4.6.5. Inter-Area Voltage Coordination

Adjacent Reliability Coordinator Areas coordinate voltage criteria and procedures and mutually agreed upon procedures for inter-Reliability Coordinator Area voltage control.

4.6.6. Parallel Flows

If an emergency is caused in whole or in part by parallel power flows, the Reliability Coordinator Area or Areas contributing to parallel power flows takes all steps, including firm load shedding, to eliminate the circulating power flow contributing to the emergency. The Area experiencing the emergency implements all steps up to and including firm load shedding in accordance with local or NERC TLR procedures.

4.6.7. Maintaining Adequate Operating Reserve

Balancing Authorities in coordination with their respective Reliability Coordinator maintain specific instructions for maintaining and reestablishing of Operating Reserve of each Area when any Area is forecasting or experiencing an Operating Reserve deficiency.

4.6.8. Emergency Operating Plans


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Reliability Coordinator, Transmission Operators, Generation Operators and Balancing Authorities develop, maintain, and implement as necessary, a set of plans to resolve operating emergencies. These plans are coordinated with each other, as appropriate.

The purpose of these plans is to present the basic factors to be considered in formulating procedures to be followed in an emergency or during conditions which could lead to an emergency, in order to facilitate mutual assistance and coordination within NPCC.

4.7. Plans for Loss of Primary Control Center Functionality

Each Reliability Coordinator, Transmission Operator and Balancing Authority maintains a plan to continue reliable operations in the event its primary control center becomes inoperable.

5. System Restoration

After a system collapse, the Reliability Coordinator and its affected responsible entities coordinate their restoration actions. Restoration priority is given to establishing the transmission system and providing station service supply to power plants. Transmission Operators, Generation Operators and Balancing Authorities avoid any action that would cause a subsequent collapse of the BPS. Customer load is restored as generation and transmission equipment becomes available, recognizing that load and generation must remain in balance at normal frequency.

5.1.Reliability Coordinator Restoration Plan

The Reliability Coordinator is aware of, and maintains a copy of, the restoration plan for each Transmission Operator in its Reliability Coordinator Area in accordance with NERC and Regional requirements. During system restoration, the Reliability Coordinator monitors restoration progress and coordinates any needed assistance.

The Reliability Coordinator maintains an Area restoration plan that provides for the reliable restoration of its Area and coordination with its responsible operating entities and the neighboring Reliability Coordinators.

5.2. Reliability Coordinator is the Primary Contact

The Reliability Coordinator serves as the primary contact for disseminating information regarding restoration to neighboring Reliability Coordinators and to responsible entities within its Reliability Coordinator Area not immediately involved in restoration.


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5.3. Reestablishing Normal Operations

The Reliability Coordinator takes actions in accordance with its restoration plan to restore normal operations once the operating emergency has been mitigated. Following a disturbance that caused the electrical isolation of one or more parts of the BPS, control actions are implemented to return the BPS to normal. These actions include:

5.3.1. Evaluate the Condition of the Bulk Power System

The affected Transmission Operators and Balancing Authorities work in conjunction with their Reliability Coordinator(s) to determine the extent and condition of the isolated areas.

5.3.2. Restore Frequency

The affected TOPs and BAs under the direction of Reliability Coordinator take the necessary action to restore the BPS frequency to normal, including adjusting generation, placing additional generators on line, or shedding load.

5.3.3. Review Interchange Schedule

The Reliability Coordinator reviews the interchange schedules within the affected areas and make the necessary adjustments to facilitate restoration. The Reliability Coordinator makes all attempts to maintain the adjusted interchange schedules irrespective of whether generation control is manual or automatic.

5.3.4. Re-synchronize

The Reliability Coordinator approves, communicates and coordinates the re-synchronization of major system islands or synchronization points so that the adjacent Reliability Coordinator Areas are not burdened.

5.4. Priority to Supply Power to Nuclear Plants

The affected Transmission Operators and Balancing Authorities work in conjunction with their Reliability Coordinator to give the highest priority to restore the power supply to nuclear stations.

5.5. Communication and Coordination

Effective communication and coordination is critical during the restoration process. Reliability Coordinators issue Operating Instructions in a clear, concise and definitive manner.


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6. Reliability Monitoring and Coordination

6.1. Coordination Agreements

The Reliability Coordinator has clear, comprehensive coordination agreements with adjacent Reliability Coordinators to identify the actions of adjacent Reliability Coordinator Areas to coordinate the mitigation of SOL or IROL exceedances.

6.2. Data Requirements

Each Reliability Coordinator determines the data requirements to support its Reliability Coordination tasks and requests such data from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and Distribution Providers, or adjacent Reliability Coordinators.

6.3. Data Exchange

Each Reliability Coordinator provides, or arranges provisions for, data exchange to other Reliability Coordinators or Transmission Operators and Balancing Authorities via a secure network.

6.3.1. Voice Communications

Each Reliability Coordinator, Transmission Operator and Balancing Authority provides adequate and reliable telecommunication facilities to ensure the exchange of interconnection and operating information necessary to maintain reliability. These facilities are provided between the Reliability Coordinator and its responsible entities and with other Reliability Coordinators as necessary to maintain reliability. Where applicable these facilities are redundant and diversely routed.

Each Reliability Coordinator and its responsible entities manage alarm, test and/or actively monitor vital telecommunications facilities. Special attention is given to emergency telecommunications facilities and equipment not used for routine communications.

6.3.2. Data Monitoring

Each Reliability Coordinator maintains detailed real-time monitoring capability of its Reliability Coordinator Area and sufficient monitoring capability of its surrounding Reliability Coordinator Areas to identify potential or actual System Operating Limit or Interconnection Reliability Operating Limit exceedances. The information provided can be easily understood and interpreted by the Reliability Coordinator’s operating


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personnel, giving particular emphasis to alarm management and awareness systems, automated data transfers, and synchronized information systems, over a redundant and highly reliable infrastructure.

6.4. Coordination and Monitoring

6.4.1. Intra-Area Monitoring and Coordination

Each of the five Areas in NPCC (New York, New-England, Ontario, Québec and the Maritimes) monitors and controls operating problems and events affecting reliability within their jurisdiction. Each TOP and BA is responsible for notifying their respective Reliability Coordinator of any abnormal conditions that require Inter-Area/Regional action.

6.4.2. Inter-Area/Regional Monitoring and Coordination

Monitoring and coordination for most operating concerns between RCs, TOPs and BAs either within the Region or with RCs, TOPs and BAs in other Regions, are carried out by the Reliability Coordinators. This includes both foreseen and unforeseen events.

The Reliability Coordinator coordinates with other Reliability Coordinators, including actions to mitigate abnormal operating conditions, actions to contain an emergency, and actions for system restoration.

6.4.3. Inter-Regional Monitoring and Coordination

6.4.3.1. Real-time:

Through use of the Eastern Interconnection Data Sharing Network (EIDSN) RCs, TOPs and BAs share specific operating information relevant to Inter-Regional operation as prescribed by NERC Reliability Standard such as Inter-tie flows, line and flowgate limits, ACE, generator status, load and frequency.

In addition, Reliability Coordinators use the Reliability Coordinator Information System (RCIS), EIDSN and the Interchange Distribution Calculator (IDC) for providing reliability and transaction information. Each communication tool is used to share and monitor essential operating parameters and/or system reliability status between Reliability Coordinators and respective Reliability Coordinator Areas. Information exchanged includes peak load, expected and required reserve, largest single contingency, MW available in 24 hours, generator and major transmission outages, unusual operating and weather conditions. The RCIS is used to send, in


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template format, text information to report on emergencies and share critical operating information with other Reliability Coordinators.

6.5. NPCC Conference Calls

6.5.1. Daily Area Control Room Coordination Conference Calls

Each morning, the NPCC Reliability Coordinator control rooms, NPCC Staff,MISO and PJM, take part in a regularly scheduled conference call. The goal of this call is to alert all neighboring Reliability Coordinators of any potential emerging problems which could lead to reliability concerns in the course of the day’s operations.

Subjects for discussion are limited to credible events which could impact the ability of a Reliability Coordinator to serve its load and meet its operating reserve obligations, or which would impose a burden to the neighboring NPCC Areas or the Eastern Interconnection.

6.5.2. Weekly Conference Calls

NPCC Staff convenes weekly conference calls to discuss expected operating conditions for the coming 7-day period. PJM and MISO also participate in these conference calls.

6.5.3. Emergency Conference Calls

NPCC has procedures in place to initiate an "Emergency Preparedness Conference Call" among the RCs of NPCC and NPCC Staff to discuss issues related to the adequacy and security of the interconnected bulk power supply system of the Northeast Power Coordinating Council. MISO and PJM also participate, as needed.

7. Reliability Applications

7.1. Analysis Tools

Each Reliability Coordinator has adequate analysis tools such as state estimation, pre- and post-contingency analysis capabilities (thermal, stability, and voltage), and Wide Area overview displays as required for maintaining BPS reliable operations.

7.2. Communication Facilities


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Each Reliability Coordinator maintains adequate communications facilities (voice and data links) to appropriate entities within its Reliability Coordinator Area. These communications facilities are staffed and available to act in addressing a real-time emergency condition.

7.3. Real Time Monitoring

Each Reliability Coordinator continuously monitors its Reliability Coordinator Area. Each Reliability Coordinator has provisions for backup facilities that are utilized if the main monitoring system is unavailable. Each Reliability Coordinator ensures that SOL and IROL monitoring and calculations continue if the main monitoring system is unavailable.

8. Staffing and Training

8.1. Reliability Coordinator Staffing Requirements

The Reliability Coordinator is staffed with adequately trained and NERC-Certified Reliability Coordinator operators, 24 hours/day, seven days/week.

8.2. Certification

Each Transmission Operator, Balancing Authority, and Reliability Coordinator staffs all operating positions that meet either one or both of the following criteria with personnel that are NERC-certified for the applicable functions:

• Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected BPS.

• Positions directly responsible for complying with NERC standards. While in training, an individual without the proper NERC certification credential may not independently fill a required operating position. Trainees may perform critical tasks only under the direct, continuous supervision and observation of the NERC certified individual filling the required position.

8.3. Staff Expertise

Reliability Coordinator operating personnel have an extensive understanding of the Balancing Authorities, Transmission Operators, and Generation Operators within the Reliability Coordinator Area, including the operating staff, operating practices and procedures, restoration priorities and objectives, outage plans, equipment capabilities, and operational restrictions.

8.4. Training

8.4.1. Training Requirements


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All Reliability Coordinators, Transmission Operators and Balancing Authorities provide their System Operators with a coordinated training program that is designed to promote the reliable operation of the BPS. This program includes objectives based on the NERC Standards and NPCC documentation.

9. NPCC Operating Considerations

9.1. ISO-NE

a) Is the Reliability Coordinator for the New England Area. b) Has the coordination responsibility to provide interconnection

protection against large source contingencies in ISO-NE. c) The ISO-NE reliability role is to limit the magnitude of the

contingencies noted above to levels which will not result in exceedance of NYISO and PJM (RF) operating criteria and will not jeopardize the reliability of the BPS. ISO-NE is responsible to control the size of these potential contingencies to achieve this objective. If necessary, ISO-NE will reduce imports on Phase II HVdc or order reduction of generation.

9.2. NYISO

a) Is the Reliability Coordinator for the New York Area. b) Is the coordinator for “Simultaneous Activation of Reserve” (SAR). c) Interacts closely with PJM and IESO to monitor and control parallel

flow effects on the Michigan-Ontario, New York–Ontario, and New York-PJM flowgates as well as NY’s internal interfaces (such as Dysinger East and Central East) which may be impacted by Lake Erie circulation.

d) Coordinates changes with adjacent Reliability Coordinators on the phase shifters with IESO, ISO-NE and PJM.

9.3. The Independent Electricity System Operator (IESO)

a) Is the Reliability Coordinator for the Ontario Area. b) Interacts closely with NYISO, MISO and PJM to monitor and control

parallel flow effects on the Michigan – Ontario, New York – Ontario, and New York – PJM flowgates as well as Ontario’s internal flowgates (such as Queenstown Flow West and Bruce Longwood Input) which may be impacted by Lake Erie circulation.

c) Coordinates with adjacent Reliability Coordinators changes on the phase shifters with Manitoba Hydro, Minnesota Power and Light, MISO, NYISO and PJM.


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9.4. System Control Department (Direction Contrôle des mouvements d’énergie), Hydro-Québec TransÉnergie

a) Is the Reliability Coordinator for the Québec Interconnection. b) Is connected to the BPS through DC facilities only and selected

isolated generation or isolated load. c) Coordinates operations with NYISO, ISO-NE, IESO and the

Maritimes.

9.5. New Brunswick Power – System Operator (NBP-SO)

a) Is the Reliability Coordinator for the Maritimes Area. b) Coordinates operations with ISO-NE through its synchronous ties to

the Eastern Interconnection, and with HQT through DC facilities. c) The NBP-SO serves as the Reliability Coordinator for New

Brunswick Power, Nova Scotia Power Incorporated, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The NBP-SO serves as the Balancing Authority for New Brunswick Power, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative are not part of the Bulk Power System.

9.6. Descriptions of Specific Operating Considerations

9.6.1. Central-East Interface (NYISO)

This interface consists of numerous transmission lines in Mohawk Valley region of upstate New York. Central–East tends to load in an easterly direction. Contingencies, such as large generation loss east of the interface can lead to voltage collapse or instability in the New York Area if the established limits are not respected. The Central-East interface is monitored by the NYISO and procedures are in place (NYISO Emergency Operations Manual) such that generation re-dispatch and/or curtailment of transactions or load shedding can be initiated by NYISO as required to maintain (or regain) a safe margin on the interface. In addition to NYISO, the impact of these changes can involve IESO, ISO-NE, HQT and/or PJM depending on conditions in effect at the time.

9.6.2. Hydro-Québec TransÉnergie Phase II HVdc Exports

The Phase II Exports to ISO‐NE are monitored by ISO‐NE to ensure that interface or voltage limits ranging from the west of PJM through NYISO will not be violated. Using real-time data from both PJM and NYISO, ISO-NE coordinates with the Québec Reliability Coordinator the maximum allowable exports from HQT on Phase


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II in order to maintain the interconnected system in a secure operating state (as per ISO-NE Transmission Operating Guides “Procedure to Protect for the Loss of Phase II Imports”).

9.6.3. Maritimes Area-New England Minimum Tie Flow

During facility out conditions, within the NBP-SO or ISO-NE areas, the 345 kV interface from northern New England to the Maritimes Area may require that minimum export levels be maintained from the Maritimes Area in order to avoid stability and voltage problems in both Areas following large source contingencies in the Maritimes Area. The amount of power flow required is monitored by ISO-NE and NBP-SO. The minimum tie flow limits are based on a number of variables including: the element that is out of service, size of the largest Maritimes Area source contingency, generator dispatch in Maine, Generator and Madawaska HVDC dispatch in NB, Status of the Lepreau Nuclear Generating Station, status of the Chester SVC, status of the Coopers Mills STATCOM, status of the Dogtown SVC, and status of Orrington Series Capacitors.

9.6.4. New Brunswick – Nova Scotia Interconnection Controlled Separation and Under Frequency Load Shedding

The province of Nova Scotia (NS) is radially connected to the Eastern Interconnection through synchronous ties with New Brunswick (NB). During heavy interface flows from NB to NS, a single contingency will initiate a controlled separation of NS from NB and the Eastern Interconnection. Upon separation, the generation deficiency in Nova Scotia may be significant enough for NS to experience frequency decline to the point of triggering the first and possibly second stage of under frequency load shedding. The risk associated with separation and under frequency load shedding has been deemed acceptable to the province of NS. The separation of NS and the potential for under frequency load shedding does not have a significant adverse impact on the Eastern Interconnection as the loss of load due to controlled separation of NS is taken into consideration for all planning and operational studies within the Maritimes Area.

10. Plan Updates and Changes

This reliability plan will be reviewed every three years for changes. The plan should be updated, re-coordinated and re-endorsed by the NERC Real Time Operating Subcommittee (RTOS) for significant changes to the way NPCC RCs plan to meet the functional requirements.

Changes to the plan that would initiate an off-cycle update, re-coordination and re-endorsement can include but are not limited to:


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• Significant changes to RC footprint BAs or TOPs (excluding new pseudo-ties) • Significant changes to RC congestion management processes • Changes that could have a significant impact on neighboring entities


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Appendix A - Agreements with External Entities

1. Coordination Agreements: • ISO-NE:

i. Coordination Agreement between ISO-NE and NBP-SO ii. Coordination Agreement between ISO-NE and NYISO

iii. Interconnections Operators Agreement between ISO-NE and HQ • NYISO:

i. NYISO Joint Operating Agreements with neighboring RCs • NBP-SO:

i. Interconnection Operators Agreement between NBP-SO and HQ-TransÉnergie

ii. Coordination Agreement between ISO-NE and NBP-SO • IESO:

i. Ontario IESO interconnection agreements with neighbouring RCs (NY-ISO, HQ-TE, MISO)

• HQ-TE: i. Common Instructions between Hydro-Quebec TransÉnergie and

IESO ii. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and NBP-SO iii. Communications Instructions for Hydro-Quebec TransÉnergie and

NYISO iv. Common Instructions between Hydro-Quebec TransÉnergie and

ISO-NE v. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and Velco. vi. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and NYPA vii. Common System Dispatch Instructions between Hydro-Quebec

TransÉnergie and ISO-NE viii. Common System Dispatch Instructions between Hydro-Quebec

TransÉnergie and ISO-NE ix. Common Operating Instructions for Niagara Mohawk Power

Corporation, d/b/a National Grid.

December 3, 2020 DRAFT for Real Time Operating Subcommittee (RTOS) Endorsement

REDLINE

Northeast Power Coordinating Council, Inc. Regional Reliability Plan

Version 12.0

Approved by the NPCC Reliability Coordinating CommitteeTask Force

on Coordination of Operations June 1, 2016December 3, 2020

NPCC Regional Reliability Plan-June 1, 2016Month XX, 2020

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NPCC System Operations Managers Working Group (CO-08): Ioan Agavriloai Independent Electricity System Operator GaëtanGaetan Benoit New Brunswick Power Corporation Caroline Bouchard Hydro-Québec TransÉnergie Stevphen Gould ISO New England, Inc. Ioan AgavriloaiLen Johnson Independent Electricity System Operator Andrey Oks Northeast Power Coordinating Council, Inc. Jon Sawyer New York ISO


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Table of Contents

EXECUTIVE SUMMARY ........................................................................................................... 10

RELIABILITY PLAN ELEMENTS............................................................................................ 12 1. TERMS .............................................................................................................................................. 12 2. NPCC RELIABILITY COORDINATORS ............................................................................................... 12

2.1. Responsibilities ...................................................................................................................... 13 2.2. Standards of Conduct and Confidentiality ............................................................................. 14 2.3. Authorizations ....................................................................................................................... 15 2.4. Delegation of Tasks ............................................................................................................... 15

3. NORMAL OPERATIONS ..................................................................................................................... 16 3.1. Next Day and Current Day Operations .................................................................................. 16

4. EMERGENCY OPERATIONS ............................................................................................................... 25 4.1. Precedence Over Commercial Operations ............................................................................. 25 4.2. Action that would Lead to an Emergency Condition ............................................................. 26 4.3. Exercising Specific Authority to Prevent and Mitigate Emergencies .................................... 26 4.4. Exercising specific Authority for Load Shedding .................................................................. 26 4.5. Communication and Coordination ......................................................................................... 27 4.6. Emergency Operations Criteria ............................................................................................. 29 4.7. Plans for Loss of Primary Control Center Functionality ....................................................... 33

5. SYSTEM RESTORATION .................................................................................................................... 33 5.1. Reliability Coordinator Restoration Plan ............................................................................... 34 5.2. Reliability Coordinator is the Primary Contact...................................................................... 34


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5.3. Reestablishing Normal Operations ........................................................................................ 34 5.4. Priority to Supply Power to Nuclear Plants ........................................................................... 35 5.5. Communication and Coordination ......................................................................................... 35

6. RELIABILITY MONITORING AND COORDINATION ............................................................................. 36 6.1. Coordination Agreements ...................................................................................................... 36 6.2. Data Requirements................................................................................................................. 36 6.3. Data Exchange ....................................................................................................................... 36 6.4. Coordination and Monitoring ................................................................................................ 37 6.5. NPCC Conference Calls ........................................................................................................ 40

7. RELIABILITY APPLICATIONS ............................................................................................................. 40 7.1. Analysis Tools ....................................................................................................................... 40 7.2. Communication Facilities ...................................................................................................... 40 7.3. Real Time Monitoring ........................................................................................................... 41

8. STAFFING AND TRAINING ................................................................................................................. 42 8.1. Reliability Coordinator Staffing Requirements ..................................................................... 42 8.2. Certification ........................................................................................................................... 42 8.3. Staff Expertise ....................................................................................................................... 43 8.4. Training ................................................................................................................................. 43

9. NPCC OPERATING CONSIDERATIONS .............................................................................................. 43 9.1. ISO-NE .................................................................................................................................. 44 9.2. NYISO ................................................................................................................................... 44 9.3. The Independent Electricity System Operator (IESO)........................................................... 44 9.4. System Control Department (Direction Contrôle des mouvements d’énergie), Hydro-Québec TransÉnergie ................................................................................................................................... 45 9.5. New Brunswick Power – System Operator (NBP-SO) .......................................................... 45 9.6. Descriptions of Specific Operating Considerations ............................................................... 46

10. PLAN UPDATES AND CHANGES ........................................................................................................ 47

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TABLE OF CONTENTS I. EXECUTIVE SUMMARY 7 II. RELIABILITY PLAN ELEMENTS 9 1. TERMS 9 2. NPCC RELIABILITY COORDINATORS 9 2.1. Responsibilities 10 2.2. Standards of Conduct and Confidentiality 11 2.3. Authorizations 11 2.4. Delegation of Tasks 12 3. NORMAL OPERATIONS 12 3.1. Next Day and Current Day Operations 12 4. EMERGENCY OPERATIONS 20 4.1. Precedence Over Commercial Operations 20 4.2. Action that would Lead to an Emergency Condition 20 4.3. Exercising Specific Authority to Prevent and Mitigate Emergencies 20 4.4. Exercising specific Authority for Load Shedding 20 4.5. Communication and Coordination 21 4.6. Emergency Operations Criteria 23 4.7. Plans for Loss of Primary Control Center Functionality 27 4.8. Establish, Maintain and Document a Regional Blackstart Capability Plan 27 5. SYSTEM RESTORATION 28 5.1 Regional Restoration Plans 28 5.2. Reliability Coordinator Restoration Plan 28 5.3. Reliability Coordinator is the Primary Contact 28 5.4. Reestablishing Normal Operations 28 5.5. Priority to Supply Power to Nuclear Plants 29 5.6. Communication and Coordination 30 6. RELIABILITY MONITORING AND COORDINATION 30 6.1. Coordination Agreements 30 6.2. Data Requirements 30 6.3. Data Exchange 30 6.4. Levels of Coordination and Monitoring 31 6.5. NPCC Conference Calls 34 7. RELIABILITY APPLICATIONS 34 7.1. Analysis Tools 34 7.2. Communication Facilities 34 7.3. Real Time Monitoring 35 8. STAFFING AND TRAINING 35 8.1. Reliability Coordinator Staffing Requirements 35 8.2. Certification 36 8.3. Staff Expertise 36 8.4. Training 36 9. NPCC OPERATING CONSIDERATIONS 37 9.1. ISO-NE 37 9.2. NYISO 37 9.3. The Independent Electricity System Operator (IESO) 37 9.4. System Control Department Hydro-Québec TransÉnergie 37 9.5. New Brunswick Power 38 9.6. Descriptions of Specific Operating Considerations 38


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Version History

Version Date Action Change Tracking (New, Errata or Revisions)

1 New 11.1 June 5, 2013 Editorial

changes and reference updates. Removal of the detailed Appendices and explicit

1. compliance language.

Revisions

1.2 June 1, 2016 Editorial 1. changes and reference updates, including:

• references to “Directives” were changed to “Operating Instructions”

• references to “violations” were changed to “exceedances”

• Reference to ISN was changed to EInet • references to “CPS” were changed to “BAAL”

Revisions

2.0 Month, date, 2020

1. Added content specified in the NERC Reliability Coordinator Reliability Plan Reference Document, including: • Version History • List of BAs and TOPs in each RC’s footprint • Pseudo-ties • Congestion management • Plan updates and changes provisions

2. Editorial changes and reference updates, including: • Reference to the applicable registration

sections of NERC ROP • Eliminated/replaced references to the

“unknown operating state” with “Real-time Assessment”

• Updates to the applicable functional entities • Reference to ISN was changed to EIDSN • Updated SPS references with RAS • Eliminating section referencing “Beyond Real

Time” as it is outside of the Regional of NERC’s RC Reliability Plan scope

3. Changes conforming with Directory revisions, including: • Directory 5 - eliminating processes and

implementation of Regional Reserve, • Directory 8 – eliminating processes for

establishing, reviewing and maintaining Regional Restoration Plan.

Revisions

Formatted: Font: 10 pt

Formatted Table









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EXECUTIVE SUMMARY The Northeast Power Coordinating Council (NPCC) Reliability Plan describes the procedures, practices and requirements implemented to facilitate the reliable operation of the Bulk Power System (BPS) within the NPCC Region. This plan replaces the NPCC Regional Reliability Plan dated June 5, 2013June 1, 2016.

The NPCC Reliability Plan outlines the following objectives:

• Identifies the regional entities that are registered with the NERC in accordance with the “NERC Reliability Functional Model-Function Definitions and Responsible EntitiesSectionSection 500 – “Organization Registration and Certification” and Appendices 5A and 5B of the FERC-approved NERC Rules of Procedure” who are responsible for performing specified reliability functions to which requirements of mandatory NERC Reliability Standards are applicableand the NERC “Reliability Standards for the Bulk Electric Systems of North America”applicable and summarizes the operating functions that will be performed by thoseat Regionalthose registered eEntityentitiesy.

• Identifies the essential industry practices to promote effective Wide Area reliability among the Reliability Coordinators (RC) within the NPCC Region: the Ontario Independent Electricity System Operator (IESO), the New York ISO (NYISO), the ISO New England, Inc. (ISO-NE), the New Brunswick Power SO (NBP-SO) and Hydro-Québec TransÉnergie.

• Identifies the Wide Area view that provides for reliability monitoring and assessment among the Reliability Coordinators.

• Documents the procedures and tools necessary for NPCC’s Reliability Coordinators to monitor and direct the real-time operation of their RC Area in coordination with their neighboring Reliability Coordinators.

• Documents the Reliability Coordinators’ authority to direct other responsible entities to take corrective actions to maintain the reliability and integrity of their respective RC Areas.

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The NPCC Reliability Plan identifies the coordination and monitoring in both the current day and day ahead timeframes. The plan describes procedures for normal and emergency states of operation and presents the processes for the sharing and dissemination of information utilizing NPCC procedures, conference calls and NERC communication tools.

The NPCC Reliability Plan identifies the procedures to maintain reliable operations through coordinated analysis and Real-time Assessments during emergencies caused by abnormal voltage conditions or transmission loading, unanticipated parallel flow, operating reserve deficiencies, and frequency deviations. and the procedures to be followed should a Reliability Coordinator enter into an unknown operating state.

The NPCC Reliability Plan also provides an overview of the RC plans and procedures for system restoration and training.




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RELIABILITY PLAN ELEMENTS

1. TermsERMS Bolded expressions used in the NPCC Reliability Plan have the meanings ascribed thereto in the “Glossary of Terms Used in NERC Reliability Standards” and the “NPCC Glossary of Terms”.

2. NPCC Reliability CoordinatorsELIABILITY COORDINATORS The NPCC Reliability Coordinators along with their Transmission Operators and Balancing Authorities for the Eastern and Québec Interconnections are:

• Independent Electricity System Operator (IESO), for the province of Ontario (known as the Ontario Area); o BAs: IESO o TOPs: IESO, Hydro One Networks, Inc.

• New York Independent System Operator (NYISO), for the state of New York (known as the New York Area); o BAs: NYISO o TOPs: NYISO, Consolidated Edison Co of NY, Inc, Long Island Power

Authority, Niagara Mohawk Power Corporation, New York State Electric & Gas, Orange and Rockland Utilities, Inc., Rochester Gas and Electric, Central Hudson Gas & Electric Corporation, Alcoa Power Generating Inc. -Long Sault Division

• Independent System Operator of New England (ISO-NE), for the New England six states: MA, CT, RI, NH, VT, and all of ME except for Maine Public Service Company and Eastern Maine Electric Cooperative states (known as the New England Area); o BAs: ISO-NE o TOPs: ISO-NE, Central Maine Power Company, Eversource Energy

Service Company, New England Power Company, Vermont Transco LLC

• New Brunswick Power – System Operator (NBP-SO), for New Brunswick Power, Nova Scotia Power Incorporated, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative are not part of the Bulk Power System. o BAs: NBP, NSPI o TOPs: NBP, NSPI

• System Control and Operations Department (Direction Contrôle et exploitation du réseau), Hydro-Québec TransÉnergie (HQT) for the Québec Interconnection and the transmission lines between Churchill Falls Generating Station (Labrador) and HQT system (known as the Québec Area).


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o BAs: HQT o TOPs: HQT

To maintain the operational reliability of the NPCC Region, the NPCC Reliability Coordinators carry out the following tasks:

• Plan for next-day operations and analyze current day operating conditions, which includes reliability analyses such as pre- and post-contingency thermal monitoring, operating reserves, area reserves, reactive reserves, voltage limits, stability, etc., that may identify operating conditions for which special procedures may be needed;

• Analyze current day operating conditions; • Implement procedures to mitigate System Operating Limit (SOL) and

Interconnection Reliability Operating Limit (IROL) exceedances on the transmission system. Regardless of the process, the Reliability Coordinator is required to ensure that the transmission system is returned to within Interconnection Reliability Operating Limits as soon as possible, but no longer than 30 minutes.

• Monitor the Wide Area and observe the Interconnection Reliability Operating Limits. Wide Area monitoring is described as the ability to monitor the complete Reliability Coordinator Area, including critical flow, Pseudo-Tie flow (if applicable) and status information from adjacent Reliability Coordinator Areas as determined by detailed system studies.

2.1. Responsibilities

1.1.1. 3.1.1.2.1.1. Reliable Operation

The Reliability Coordinator is responsible for the reliable operation of its Reliability Coordinator Area in accordance with NPCC and NERC proceduresStandards. The Reliability Coordinator will assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundaries.

3.1.2.2.1.2. Wide Area View The Reliability Coordinator is responsible for having the Wide Area view, the operating tools, processes and procedures, including the authority, to prevent or mitigate emergency operating situations in both next-day analysis and during real-time conditions.

3.1.3.2.1.3. Authority The Reliability Coordinator has clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, and Distribution Providers, Transmission Service Providers, Load-Serving Entities,

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and Purchasing-Selling Entities within its Reliability Coordinator Area to preserve the integrity and reliability of the Bulk Power System (BPS). These actions are taken without delay, but no longer than 30 minutes.

3.1.4.2.1.4. Delegation If a Reliability Coordinator delegates tasks to others, the Reliability Coordinator retains its responsibilities for complying with NERC and regional standards.

All responsibilities for complying with NERC and regional standards applicable to Reliability Coordinators remain with the Reliability Coordinator.

1.1.2.2. Standards of Conduct and Confidentiality

2.2.1. Standards of Conduct The NPCC Reliability Coordinator adheres to the NERC Confidentiality Agreement for “Electric System Reliability Data” and the NPCC Code of Conduct


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Standards of Conduct and Confidentiality

1.1.1. Standards of Conduct The NPCC Reliability Coordinator adheres to the NERC Confidentiality

Agreement for “Electric System Reliability Data” and the NPCC Code of Conduct

1.2.2.3. AuthorizationsAuthorizations

1.1.1.2.3.1. Serving the interests of the NPCC Reliability Coordinator Areas

The Reliability Coordinator acts in the interests of reliability first for the overall Reliability Coordinator Area and the Interconnection before the interests of any other entity.

1.1.2.2.3.2. Compliance with Reliability Coordinator Operating Instructions

Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling EntitiesDistribution Providers comply with Reliability Coordinator Operating Instructions unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, these entities immediately inform the Reliability Coordinator of the inability to perform the Operating Instruction so that the Reliability Coordinator may implement alternate remedial actions.

2.4. Delegation of Tasks

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Delegation of Tasks

1.1.3.2.4.1. Delegating Tasks

The Reliability Coordinator may delegate tasks to other entities, if this delegation is accompanied by formal operating agreements, with each entity to which tasks are delegated. The Reliability Coordinator verifies that all delegated tasks are understood, communicated, and addressed within its Reliability Coordinator Area. The Reliability Coordinator lists within its reliability plan all entities to which the Reliability Coordinator has delegated tasks. Reliability Coordinators that delegate tasks consist of the following:.

• ISO-NE: None

• NYISO: None

• IESO: None

• NBP-SO: None

• HQT: None

Each Transmission Operator, Balancing Authority, and Reliability Coordinator staffs all operating positions that meet both of the following criteria with personnel that are NERC certified for the applicable functions:

(i) Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected BPS.

(ii) Positions directly responsible for complying with NERC standards.

3. NORMAL OPERATIONSNormal Operations

1.3.3.1. Nextext Day and Current Day Operations

3.1.1. Common Tasks to Next Day and Current Day Operations

1.1.3.1.3.1.1.1. Assess Contingency Situations

The Reliability Coordinator conducts Operational Planning Analysis and system assessment Real-time Assessments based on thermal, voltage and stability limits to coordinate current day and next day operations within applicable SOL and IROL. The Wide Area view of the Reliability Coordinator is modeled to meet the requirements of coordinated operations. modeled to meet the requirements of coordinated operations.




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1.1.3.2.3.1.1.2. Determine IROL

The Reliability Coordinator determines an IROL based on local, Regional and inter-Regional studies. The Reliability Coordinator must recognize that an IROL exceedance can be created during multiple, normally non-critical outage conditions and, as such, the Reliability Coordinator must be knowledgeable of events that could lead to such an occurrence. The Reliability Coordinator is responsible for disseminating this information within its Reliability Coordinator Area and to neighboring Reliability Coordinators.

1.1.3.3.3.1.1.3. Ensure that each Reliability Coordinator Area Does Not Burden Aadjacent Reliability Coordinator Area

The Reliability Coordinator operates to prevent the likelihood that a disturbance, action, or non-action in its Reliability Coordinator Area will result in a SOL or IROL exceedance in another Area of the Interconnection. In instances where the derived operating limits differ from one Area to another, the Reliability Coordinators operates the BPS to the most limiting parameter.

Each Reliability Coordinator monitors parallel flows which can place an unacceptable or undue burden on an adjacent Reliability Coordinator Area.

1.1.3.4.3.1.1.4. Transfer Capability Coordination

The Reliability Coordinator makes known to Transmission Service Providers within its Reliability Coordinator Area, SOLs or IROLs within its Wide Area view. The TSP respects these SOLs or IROLs in the determination of transfer capabilities, in accordance with filed tariffs and/or regional TTC/ATC calculation processes.

1.1.3.5.3.1.1.5. Communicate Effectively

The Reliability Coordinator issues Operating Instructions in a clear, concise and definitive manner.

1.1.3.6.3.1.1.6. Maintain Flows Within Limits

The Reliability Coordinator identifies the cause of the potential or actual SOL or IROL exceedance and initiates the control action or emergency procedure to relieve the potential or actual SOL or IROL exceedance consistent with NERC Reliability Standards.


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The Reliability Coordinator evaluates actions taken to address an IROL or SOL exceedance and, if the actions taken are not appropriate or sufficient, direct actions required to return the system to within limits.

1.1.3.7.3.1.1.7. Maintain a Wide Area View

Each Reliability Coordinator monitors all BPS facilities, which may include sub-transmission information, within its Reliability Coordinator Area and adjacent Reliability Coordinator Areas via the Eastern Interconnection Data Sharing Network (EIDSN)Interregional Security Network (ISN),, as necessary to ensure that, at any time, regardless of prior planned or unplanned events, the Reliability Coordinator is able to determine any potential SOL and IROL exceedances within its Reliability Coordinator Area.

Each Reliability Coordinator notifies specific neighboring RCs when an element listed in the NPCC Facilities Notification List1 is scheduled to be removed from service or has been removed from service due to a forced outage event.

Each Reliability Coordinator is aware of the current status of all critical facilities whose failure, degradation or disconnection could result in an SOL or IROL exceedance. Reliability Coordinators are aware of the status of any facilities that may be required to assist area restoration objectives.

1.1.3.8.

1 NPCC Regional Reliability Reference Directory # 1 - Design and Operation of the Bulk Power System, Appendix F – Procedure for Operational Planning Coordination, Section 4.2 – “The Facilities Notification List is developed by each RC Area and specifies all facilities that, if removed from service, may have a significant, direct or indirect impact on another RC Area’s transfer capability. The cause of such impact might include stability, voltage, and/or thermal considerations.”




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1.1.3.9.3.1.1.8. Inter-Area/Inter-Regional Coordination

Reliability Coordinators are responsible for addressing inter-Area or inter-Regional operational concerns by coordinating their actions with other Reliability Coordinators from the NPCC Region and other Regions. This includes both foreseen and unforeseen events. Reliability Coordinators are responsible for taking immediate actions to contain an operating problem and to request or provide assistance from or to other Reliability Coordinators.

The Reliability Coordinator coordinates with other Reliability Coordinators and other responsible entities as needed to develop and implement action plans to mitigate potential or actual SOL, IROL, BAAL exceedances or DCS violations. This includes coordination of pending generation and transmission maintenance outages in both the current-day and next-day timeframes. It also includes coordination of any actions, including emergency assistance, required to mitigate any operational concerns.

When a Reliability Coordinator is aware of an operational concern, such as declining voltages, excessive reactive flows, or an IROL exceedance, in a neighboring Reliability Coordinator Area, it contacts the Reliability Coordinator in whose Area the operational concern was observed. The two Reliability Coordinators coordinate any actions, including emergency assistance, required to mitigate the operational concern.

3.1.2. Next-Day Operations

1.1.3.10.3.1.2.1. Reliability Analysis and System Studies

The Reliability Coordinator conducts next-day Operational Planning Analysis reliability analyses for its Reliability Coordinator Area.

1.1.3.10.1.3.1.2.1.1. Contingency Analysis

The Reliability Coordinator conducts contingency analysis studies to identify potential interface and other SOL and IROL exceedances.

1.1.3.10.2.3.1.2.1.2. Parallel Flows


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Parallel Flows

Each Reliability Coordinator monitors parallel flows which place an unacceptable or undue burden on an adjacent Reliability Coordinator Area.

1.1.3.11.3.1.2.2. Information Sharing

Each responsible entity in the Reliability Coordinator Area provides to its Reliability Coordinator all information required for system studies, such as critical facility status, load, generation, Operating Reserve projections and known interchange transactions.

1.1.3.12.3.1.2.3. Action Plan Development

The Reliability Coordinator, in conjunction with its responsible entities, develops action plans that address operational concerns by reconfiguring the transmission system, re-dispatching generation, reducing or curtailing interchange transactions, or reducing firm load to return the transmission loading to within acceptable SOL and IROL.

1.1.3.13.3.1.2.4. Sharing of Study Results

When conditions warrant or upon request, the Reliability Coordinator shares the results of its system studies with responsible entities within its Reliability Coordinator Area or with other Reliability Coordinators.

When required, the Reliability Coordinator initiates a conference call or other appropriate communications to address the results of its reliability analyses.

1.1.3.14.3.1.2.5. Issuing NotificationsAlerts

If after applying all possible mitigation action plans, the study results indicate potential SOL or IROL exceedances, the Reliability Coordinator issues the appropriate notifications alerts via the Reliability Coordinator Information System (RCIS) and directs its responsible entities to take the necessary actions to address the potential SOL or IROL exceedance...

1.1.3.15.3.1.2.6. Compliance with Reliability Coordinator Operating Instructions


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Compliance with Reliability Coordinator Operating Instructions

All responsible entities comply with the Operating Instructions of their Reliability Coordinator based on the next day assessments in the same manner in which they would comply during real time operating events.

3.1.3. Current Day Operations

1.1.3.16.3.1.3.1. Status of Facilities

The Reliability Coordinator must be aware of the status of all facilities whose failure, degradation or disconnection could result in an SOL or IROL exceedance. Reliability Coordinators must also be aware of the status of any facilities that may be required to assist Area restoration objectives.

1.1.3.17.3.1.3.2. Situational Awareness

The Reliability Coordinator maintains awareness of operating conditions within its Reliability Coordinator Area and includes this information in its reliability assessmentsReal-time Assessment, including but not limited to the following, where applicable:

• Current status of the BPS, including, the status of automatic voltage regulators (AVR) and special protection systems (SPS) / Remedial Action Schemes (RAS).

• Current pre-contingency and post-contingency element conditions (voltage, thermal, or stability).

• Operating Reserve. • Reactive Reserves. • Capacity and energy adequacy conditions. • Current ACE for all its Balancing Authorities. • Area congestion management or TLR procedures in

effect. • Planned generation dispatches. • Planned transmission or generation outages • Contingency events.

1.1.3.18.3.1.3.3. Interchange Transaction Monitoring

The Reliability Coordinator monitors interchange.

1.1.3.18.1.3.1.3.3.1. Interchange Transaction Information



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The Reliability Coordinator is aware of all interchange transactions that wheel-through, source, or sink in its Reliability Coordinator Area.

1.1.3.18.2.3.1.3.3.2. Pending Interchange Schedules to Identify Potential Flow Impacts

As portions of the transmission system approach or exceed SOLs or IROLs, the Reliability Coordinator works with its responsible entities to evaluate and assess any additional Interchange Schedules that would exceed those limits. If the potential or actual SOL or IROL exceedance cannot be avoided through proactive intervention, the Reliability Coordinator initiates control actions or emergency procedures to relieve the exceedance. All resources, including the shedding of firm load, are available to the Reliability Coordinator to address a potential or actual SOL or IROL exceedance.

1.1.3.19.3.1.3.4. Time Error Correction (TEC) and Geomagnetic Disturbance Notification

EachThe Reliability Coordinator communicates and implements start and end times for time error corrections to the relevant responsible entities within its Reliability Coordinator Area, .in accordance with the NERC Time Monitoring Reference Document.

NPCC contracts with the Solar Terrestrial Dispatch (STD) for a solar notification and communication system used by the five Reliability Coordinators, the Geomagnetic Storm Mitigation System (GSMS). An active communications software package installed on the system operator’s console provides each of the NPCC RCs with geomagnetic storm alerts and the status of solar activity. Upon receipt of a geomagnetic storm alert of Kp = 6 or higher, the GSMS simultaneously provides:

• • visual and / or audible alarms; • • a main screen providing the system operator with all

information currently known about possible solar activity; and

• • a dialog box permitting instantaneous communication among all NPCC Reliability Coordinators of any observed solar magnetic phenomenon.


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Complementing the notification system, NPCC also established its Document C-15, “Procedures for Geomagnetic Disturbances Which Affect Electric Power Systems,” establishing protective measures which can be taken to minimize the vulnerability of the system to solar phenomenon. After reviewing the available data provided by the GSMS, the system operatorReliability Coordinator may choose to enact one or more of the actions presented in Document C-15.”

1.1.3.20.3.1.3.5. System frequency and resolution of significant frequency errors, deviations and real-time trends.

The Reliability Coordinator monitors system frequency and it’s its Balancing Authorities’ performance and directs any necessary re-balancing to return to BAAL and DCS compliance. The Transmission Operators and Balancing Authorities utilizes all resources, including the shedding of firm load, as directed by its Reliability Coordinator to relieve the emergent condition.

The Reliability Coordinator identifies sources of large Area Control Errors that may be contributing to Frequency Error, Time Error, or Inadvertent Interchange and discusses corrective actions with the appropriate Balancing Authority. If a sustained and unexplained Frequency Error, Time Error, or inadvertent problem occurs outside of the Reliability Coordinator Area, is observed the Reliability Coordinator may initiates a NERC hotline call to discuss the Frequency Error, Time Error, or Inadvertent Interchange with other Reliability Coordinators.

1.1.3.21.3.1.3.6. Monitoring of Special Protection Systems (SPS)/Remedial Action Schemes (RAS)

Whenever an SPS/RAS Special Protection System that may have an inter-Balancing Authority, inter-Transmission Operator, or inter-Reliability Coordinator Area impact (e.g., could potentially affect transmission flows resulting in a SOL or IROL exceedance) is armed, the Reliability Coordinators are aware of the impact of the operation of that Special Protection SystemSPS/RAS on inter-area flows. The Transmission Operator immediately informs the Reliability Coordinator of the status of the Special Protection System SPS/RAS including any degradation or potential failure to operate as expected.



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3.1.3.7. Congestion management

The RCs utilize security constrained dispatch to provide a secured solution for the internal transmission system, including generator dispatch and transaction scheduling.

RCs have a number of control actions available in order to manage congestion on internal and external (i.e. shared) constraints; some or all of these control actions may be used as applicable to manage congestion. These control actions include adjusting phase angle regulators, arming SPS/RAS, suspending or decreasing inadvertent payback, recalling outages, adjusting internal generation and dispatchable load through re-dispatch of resources, curtailing import/export transactions.

Additionally, where applicable, for external constraints management control actions include using the NERC transmission loading relief (TLR) procedure.

3.1.3.8. Congestion management agreements

Neighboring RCs within NPCC have agreements that address coordinated transaction scheduling and congestions management protocols. The list of the agreements can be found in the applicable coordination agreements, as specified in the Appendix A - Agreements with external entities. Issuing Alerts

The Reliability Coordinator who foresees a transmission problem (such as an SOL or IROL exceedance, loss of reactive reserves or any emergency operating conditions) within its Reliability Coordinator Area issues an alert to all impacted entities within its Area, and to all Reliability Coordinators within the Interconnections via the Reliability Coordinator Information System (RCIS. The receiving Reliability Coordinator disseminates this information to its impacted entities and notifies all when the transmission problem has been mitigated.

4. EMERGENCY OPERATIONSEmergency Operations Emergency Operations Plans - Each Reliability Coordinator shall have a comprehensive Operating Plan to prepare for and mitigate Operating Emergencies on the Bulk Power System. The Operating Plan may consist of numerous procedures or processes. The purpose of an Emergency Operations Plan is to identify the RC, BA, and TOP roles, responsibilities and processes to prepare for and mitigate Operating Emergencies.

4.1. Precedence Over Commercial Operations



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The integrity and reliability of the BPS is of paramount importance and takes precedence over the interest of any other entity.

1.4.4.2. Action that would Lead to an Emergency Condition

Reliability Coordinators and Transmission Operators, Generator Operators and Balancing Authorities do not take any action, or refrain from taking any action, that would, knowingly lead to an emergency condition within their Area or a neighboring Area.

1.5.4.3. Exercising Specific Authority to Prevent and Mitigate Emergencies

Reliability Coordinators and Balancing Authorities and Transmission Operators have the responsibility and decision-making authority for maintaining the reliability of the BPS and exercise their specific authority to prevent and mitigate capacity and energy emergencies.

1.6.4.4. Exercising specific Authority for Load Shedding

The Reliability Coordinator has clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling EntitiesDistribution Providers within its Reliability Coordinator Area to preserve the integrity and reliability of the BPS.



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A Balancing Authority and Transmission Operator operating with insufficient generation or transmission capacity has the capability and authority to shed load.

1.7.4.5. Communication and Coordination

1.1.4.4.5.1. Effective Communication

Effective communication is critical during an emergency or as an emergency situation evolves. In order to mitigate the consequences of the event, NPCC Reliability Coordinators issue Operating Instructions in a clear, concise and definitive manner.

1.1.5.4.5.2. Notification of Potential Problems/Emergency

An NPCC Reliability Coordinator who foresees a transmission problem (such as an SOL or IROL exceedance, loss of reactive reserves, any emergency operating conditions, etc.) within its Reliability Coordinator Area issues an alert tonotifies all impacted Transmission Operators and Balancing Authorities in its Reliability Coordinator Area, and to all impacted Reliability Coordinators within the Interconnection. via the Reliability Coordinator Information System (RCIS).

1.1.6.4.5.3. Disseminating/Sharing Information

NPCC Reliability Coordinators use the NERC Hotline to disseminate information and exercise coordination with other Reliability Coordinators. Appropriate information is then disseminated to individual Balancing Authorities and Transmission Operators within their Reliability Coordinator Area.

1.1.7.4.5.4. NERC Hotline

For emergencyies and near emergency situations that involve or affect the BPS, or when time is of the essence in the recognition, prevention, mitigation or resolution of the emergency, Reliability Coordinators may employ the NERC Hotline.

1.1.8.4.5.5. NERC RCIS


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NERC RCIS

NPCC Reliability Coordinators may use the RCIS or other methods to provide notification of potential or actual emergency conditions. Such notifications include information regarding abnormal system conditions, which have the potential to burden neighboring Reliability Coordinators Areas such as:

• Extreme weather conditions that are likely to adversely impact the reliability of the BPS;

• Energy Emergency Alert; • Request for emergency energy assistance; • Major forced transmission and generation outages that

have, or are likely to have, an adverse impact on the reliability of the BPS;

• Abnormal voltage and frequency conditions.

1.1.8.1.4.5.5.1. NPCC Emergency Preparedness Conference Calls

To quickly exchange information about the current status of the BPS, to facilitate inter-Area emergency assistance, or to evaluate a physical threat to the systems, the Reliability Coordinators in NPCC may initiate an "NPCC Emergency Preparedness Conference Call." It may include representatives from PJM and MISO, as necessary.

1.1.9.4.5.6. Communication During Extended Emergencies

During extended emergencies, NPCC Reliability Coordinators provide effective, timely and accurate information to key entities such as media, government and regulatory bodies to facilitate public awareness and cooperation.

1.1.10.4.5.7. Energy Emergency Alerts

A Reliability Coordinator that is forecasting a potential, or experiencing an actual, Energy Emergency within its Reliability Coordinator Area initiates an Energy Emergency Alert via the RCIS.


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1.8.4.6. Emergency Operations Criteria

1.1.11. Unknown Operating State 1.1.12. If the Transmission Operator enters an unknown operating state

(e.g. any state for which valid operating limits have not been determined), it is considered to be in an emergency and restores operations to respect proven reliable power system limits within 30 minutes.

1.1.13.4.6.1. Disconnecting Facilities

NPCC Transmission Operators and Generator Operator notify and coordinate with their Reliability Coordinator and Balancing Authority, as applicable and adjacent Transmission Operator before removing BPS facilities from service if removing those facilities would burden a neighboring Area.

For a generator outage, the Generator Operator notifies and coordinates with the Transmission Operator and Balancing Authority. The Transmission Operator and Balancing Authority notifies the Reliability Coordinator and other affected Transmission Operators, and coordinates the impact of removing the BPS facility.

For a transmission facility, the Transmission Operator notifies and coordinates with its Reliability Coordinator. The Transmission Operator notifies other affected Transmission Operators, and coordinates the impact of removing the BPS facility.

When time does not permit such notifications and coordination, or when immediate action is required to prevent a hazard to the public, lengthy customer service interruption, or damage to facilities, the Generator Operator notifies the Transmission Operator and Balancing Authority , and the Transmission Operator notifies its Reliability Coordinator and adjacent Transmission Operators, at the earliest possible time.

The NPCC Reliability Coordinators maintain the NPCC list of "Facilities for Notification" that, if removed from service, may directly or indirectly burden a neighboring Transmission Operator.

1.1.14.4.6.2. Operating Within Limits

The Reliability Coordinator makes available to its operators a comprehensive set of operating limits for both normal and emergency conditions, including clear instructions describing the circumstances when these limits are to be used.


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Where inter-Area reliability is affected, the Reliability Coordinator establishes limits and operates so that the contingencies can be withstood without adversely affecting other Areas. During emergencies, the Reliability Coordinator is required to operate within the applicable emergency System Operating Limits (SOL) and Interconnection Reliability Operating Limits (IROL). The Reliability Coordinator is required to implement emergency measures, including shedding of firm load, to maintain the operation of the power system within the applicable emergency limits.

In instances where there is a difference in derived limits, the Reliability Coordinator operates the BPS to the most limiting parameter.

The Reliability Coordinators and Transmission Operators have sufficient real time information and analysis tools to determine potential SOL or IROL exceedances. This analysis is conducted in all operating timeframes. The Reliability Coordinator uses the results of these analyses to determine the causes of the exceedances and identify mitigating actions.

Each Reliability Coordinator identifies the cause of any potential or actual SOL or IROL exceedances. The Reliability Coordinator initiates the control action or emergency procedure to relieve the potential or actual IROL exceedance without delay, and no longer than 30 minutes. The Reliability Coordinator is able to utilize all resources, including load shedding, to address an IROL exceedance.

When an SOL or IROL exceedance is imminent, Reliability Coordinators must be aware that Transmission Loading Relief (TLR) procedures may not be able to address the exceedance in a timely fashion. In such circumstances the Reliability Coordinators have the authority and obligation to immediately direct their Transmission Operators, Generation Operators and Balancing Authorities to re-dispatch generation, reconfigure transmission, manage interchange transactions, or reduce system demand which may include shedding of firm load. These actions are used in conjunction with the TLR procedure to restore the system to normal state. The Reliability Coordinator coordinates these emergency control actions with other Reliability Coordinators as needed.

1.1.15.4.6.3. Frequency Control

The Reliability Coordinator identifies sources of large Area Control Error that may be contributing to frequency error, time error, or inadvertent interchange and discusses corrective actions with the appropriate Balancing Authority. If a Frequency Error, Time Error, or inadvertent problem occurs, the Reliability


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Coordinator initiates a NERC hotline call to discuss the frequency error, time error, or inadvertent interchange with other Reliability Coordinators, as appropriate. The Reliability Coordinator directs its Balancing Authorities to comply with BAAL andBAALand DCS.

During a system emergency, the Reliability Coordinator complies with NERC BAL Standards. The Reliability Coordinator does not rely on the frequency bias of the other Transmission Operators, Generation Operators and Balancing Authorities to provide energy during the emergency because doing so reduces the Interconnection’s ability to recover its frequency following additional generator failures.

If the Reliability Coordinator determines that Balancing Authorities within its Area cannot comply with the NERC BAL Standards, then it declares an Energy Emergency and implement remedies such as requesting assistance from other Reliability Coordinators, or implementing load reduction through public appeals, voltage reductions, curtailing interruptible loads and shedding firm load to return ACE to acceptable BAAL and DCS criteria.

1.1.16.4.6.4. Reactive Power Balance and Voltage Control

When an Area is experiencing abnormal voltage conditions, its Reliability Coordinator takes action to restore the reactive power balance. The Reliability Coordinator implements corrective control actions, which include requesting emergency assistance. If these actions are still not adequate to mitigate the reactive power imbalance then the Reliability Coordinator takes all necessary steps to relieve the abnormal voltage conditions, including firm load shedding.

1.1.17.4.6.5. Inter-Area Voltage Coordination

Adjacent Reliability Coordinator Areas coordinateare familiar with each other’s voltage criteria and procedures and mutually agreed upon procedures for inter-Reliability Coordinator Area voltage control.

1.1.18.4.6.6. Parallel Flows

If an emergency is caused in whole or in part by parallel power flows, the Reliability Coordinator Area or Areas contributing to parallel power flows takes all steps, including firm load shedding, to eliminate the circulating power flow contributing to the emergency. The Area experiencing the emergency implements all


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steps up to and including firm load shedding in accordance with local or NERC TLR procedures.

1.1.19.4.6.7. Maintaining Adequate Operating Reserve

NPCC Balancing Authorities in coordination with their respective Reliability Coordinator maintains specific instructions for maintaining and reestablishing the redistribution of Operating Reserve of each among Areas when any Area is forecasting or experiencing an Operating Reserve deficiency.


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1.1.20.4.6.8. Emergency Operating Plans

Reliability Coordinator, Transmission Operators, Generation Operators and Balancing Authorities develop, maintain, and implement as necessary, a set of plans to resolve operating emergencies. These plans are coordinated with each other, as appropriate.

The purpose of these plans is to present the basic factors to be considered in formulating procedures to be followed in an emergency or during conditions which could lead to an emergency, in order to facilitate mutual assistance and coordination within NPCC.

1.9.4.7. Plans for Loss of Primary Control Center Functionality

Each Reliability Coordinator, Transmission Operator and Balancing Authority maintains a plan to continue reliable operations in the event its primary control center becomes inoperable.

1.2. ESTABLISH, MAINTAIN AND DOCUMENT A REGIONAL BLACKSTART CAPABILITY PLAN

A System Blackstart Capability Plan (BCP) identifies the quantity and location of system blackstart generators to perform their expected functions as specified in the overall coordinated Regional System Restoration Plans (SRP).

4.5.System Restoration


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SYSTEM RESTORATION

After a system collapse, the Reliability Coordinator and its affected responsible entities coordinate their restoration actions. Restoration priority is given to establishing the transmission system and providing station service supply to power plants. Transmission Operators, Generation Operators and Balancing Authorities avoid any action that would cause a subsequent collapse of the BPS. Customer load is restored as generation and transmission equipment becomes available, recognizing that load and generation must remain in balance at normal frequency.

1.10. Regional Restoration Plans 1.11. The Regional Reliability Organizations maintain a coordinated

Regional System Restoration Plan. Each Regional Reliability Organization maintains a system BCP, as part of an overall coordinated Regional System Restoration Plan.

1.12.5.1. Reliability Coordinator Restoration Plan

The Reliability Coordinator is aware of, and maintains a copy of, the restoration plan for each Transmission Operator in its Reliability Coordinator Area in accordance with NERC and Regional requirements. During system restoration, the Reliability Coordinator monitors restoration progress and coordinates any needed assistance.

The Reliability Coordinator maintains an Area restoration plan that provides for the reliable restoration of its Area and coordination with its responsible operating entities and the neighboring Reliability Coordinators.

1.13.5.2. Reliability Coordinator is the Primary Contact

The Reliability Coordinator serves as the primary contact for disseminating information regarding restoration to neighboring Reliability Coordinators and to responsible entities within its Reliability Coordinator Area not immediately involved in restoration.

1.14.5.3. Reestablishing Normal Operations

The Reliability Coordinator takes actions in accordance with its restoration plan to restore normal operations once the operating emergency has been mitigated. Following a disturbance that caused the electrical isolation of one or more parts of the BPS, control actions are implemented to return the BPS to normal. These actions include:

1.1.21.5.3.1. E



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Evaluate the Condition of the Bulk Power System

The affected Transmission Operators and Balancing Authorities work in conjunction with their Reliability Coordinator(s) to determine the extent and condition of the isolated areas.

1.1.22.5.3.2. Restore Frequency

The affected TOPs and BAs under the direction of Reliability Coordinator take the necessary action to restore the BPS frequency to normal, including adjusting generation, placing additional generators on line, or shedding load.

1.1.23.5.3.3. Review Interchange Schedule

The Reliability Coordinator reviews the interchange schedules within the affected areas and make the necessary adjustments to facilitate restoration. The Reliability Coordinator makes all attempts to maintain the adjusted interchange schedules irrespective of whether generation control is manual or automatic.

1.1.24.5.3.4. Re-synchronize

The Reliability Coordinator approves, communicates and coordinates the re-synchronization of major system islands or synchronization points so that the adjacent Reliability Coordinator Areas are not burdened.

1.15.5.4. Priority to Supply Power to Nuclear Plants

The affected Transmission Operators and Balancing Authorities work in conjunction with their Reliability Coordinator to give the highest priority to restore the power supply to nuclear stations.

1.16.5.5. Communication and Coordination


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Communication and Coordination

Effective communication and coordination is critical during the restoration process. Reliability Coordinators issue Operating Instructions in a clear, concise and definitive manner.

5.6.Reliability Monitoring and Coordination

1.17.6.1. Coordination Agreements

The Reliability Coordinator has clear, comprehensive coordination agreements with adjacent Reliability Coordinators to identify the actions of adjacent Reliability Coordinator Areas to coordinate the mitigation of SOL or IROL exceedances.

1.18.6.2. Data Requirements

Each Reliability Coordinator determines the data requirements to support its Reliability Coordination tasks and requests such data from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and Distribution Providers, or adjacent Reliability Coordinators.

1.19.6.3. Data Exchange

Each Reliability Coordinator provides, or arranges provisions for, data exchange to other Reliability Coordinators or Transmission Operators and Balancing Authorities via a secure network.

1.1.25.6.3.1. Voice Communications

Each Reliability Coordinator, Transmission Operator and Balancing Authority provides adequate and reliable telecommunication facilities to ensure the exchange of interconnection and operating information necessary to maintain reliability. These facilities are provided between the Reliability Coordinator and its responsible entities and with other Reliability Coordinators as necessary to maintain reliability. Where applicable these facilities are redundant and diversely routed.

Each Reliability Coordinator and its responsible entities manage alarm, test and/or actively monitor vital telecommunications facilities. Special attention is given to emergency telecommunications facilities and equipment not used for routine communications.

1.1.26.6.3.2. Data Monitoring


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Data Monitoring

Each Reliability Coordinator maintains detailed real-time monitoring capability of its Reliability Coordinator Area and sufficient monitoring capability of its surrounding Reliability Coordinator Areas to identify potential or actual System Operating Limit or Interconnection Reliability Operating Limit exceedances. The information provided can be easily understood and interpreted by the Reliability Coordinator’s operating personnel, giving particular emphasis to alarm management and awareness systems, automated data transfers, and synchronized information systems, over a redundant and highly reliable infrastructure.

1.20.6.4. Levels of Coordination and Monitoring

1.1.27.6.4.1. Level I – Intra-Area Monitoring and Coordination

Each of the five Areas in NPCC (New York, New-England, Ontario, Québec and the Maritimes) monitors and controls operating problems and events affecting reliability within their jurisdiction. Each TOP , TO and BA is responsible for notifying their respective Reliability Coordinator of any abnormal conditions that require Inter-Area/Regional action.

1.1.28.1.1.1. The Reliability Coordinator coordinates with other Reliability Coordinators, including actions to mitigate abnormal operating conditions, actions to contain an emergency, and actions for system restoration.

1.1.29.6.4.2. Level II – Inter-Area/Regional Monitoring and Coordination

Monitoring and coordination for most operating concerns between RCs, TOPs and BAs either within the Region or with RCs, TOPs, TOs and BAs in other Regions, are carried out by the Reliability Coordinators. This includes both foreseen and unforeseen events.

The Reliability Coordinator coordinates with other Reliability Coordinators, including actions to mitigate abnormal operating conditions, actions to contain an emergency, and actions for system restoration.

This level refers to the monitoring and coordination performed by each Reliability Coordinator within its own Area. Reliability Coordinators are responsible to take immediate actions through the TOP, TO and BA under their control to contain an operating problem and coordinate assistance with other Reliability Coordinators, when needed.


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NYISO, on behalf of the NPCC Region, performs the following monitoring and coordination functions:

Request Areas to provide assistance to a deficient Area and to coordinate energy transfers between Areas to restore the ten-minute reserve.

6.4.3. Level III – Inter-Area/Inter-Regional Monitoring and Coordination

1.1.29.1.6.4.3.1. a) Real-time:

Monitoring and coordination for most operating concerns between RCs, TOPs and BAs either within the Region or with RCs, TOPs, TOs and BAs in other Regions, are carried out by the Reliability Coordinators. This includes both foreseen and unforeseen events.

Through use of the EInet Eastern Interconnection Data Sharing Network (EIDSN) RCs, TOPs and BAs share specific operating information relevant to Inter-Regional operation as prescribed by NERC Reliability Standard such as Inter-tie flows, line and flowgate limits, ACE, generator status, load and frequency.

In addition, Reliability Coordinators use the Reliability Coordinator Information System (RCIS), System Data Exchange (SDXInterregional Security Network (ISN))) EIDSN and the Interchange Distribution Calculator (IDC) for providing reliability and transaction information. Each communication tool is used to share and monitor essential operating parameters and/or system reliability status between Reliability Coordinators and respective Reliability Coordinator Areas. Information exchanged includes peak load, expected and required reserve, largest single contingency, MW available in 24 hours, generator and major transmission outages, unusual operating and weather conditions. The RCIS is used to send, in template format, text information to report on emergencies and share critical operating information with other Reliability Coordinators.


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1.21. b) Monitoring and Coordination Beyond Real-time:

In 2006, the six Regional Managers within the Eastern Interconnection developed and executed an agreement that governs the interregional assessment studies in the Eastern Interconnection. That agreement replaced the previous unilateral interregional agreements and established an Eastern Interconnection Reliability Assessment Group (ERAG) Management Committee (MC) that now oversees all of the interregional study activities. The former MACC-ECAR-NPCC (MEN) and VACAR-ECAR-MACC (VEM) forums have evolved to become the ReliabilityFirst (RF)-NPCC and RF-SERC Reliability Corporation study forums, respectively. The former studies in the western portion of the Eastern Interconnection have formed the RF-Midcontinent Reliability Organization (MRO)-Southwest Power Pool (SPP)-SERC West forum. The activities of these three forums are now directed by the ERAG MC. NPCC staff and representatives from NPCC Areas are members of the ERAG MC and the RF-NPCC Steering Committee and Working Group and participate in all activities.

The study forums appraise the anticipated near-term and future performance of the BPS within their respective Regions. That appraisal work can utilize interregional power flows, inertial responses, transient stability studies, and other appropriate program packages which may be available to appraise the ability of the interregional network to withstand representative severe contingencies without causing widespread cascading outages. The goal of these appraisals is to provide assurance that system developments and operating procedures within each Region are being properly coordinated so they do not adversely affect other Regions.

1.22. In late 2006, the NERC Planning Committee (PC) transferred oversight of the Multiregional Modeling Working Group (MMWG) to ERAG, which now reports to the ERAG MC. The MMWG has responsibility for all power flow and dynamic simulation base case model development activities, including a series of future year models and seasonal updates to summer and winter study models. NPCC staff has membership on the MMWG and participates in all activities.


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NPCC Conference Calls 6.5. NPCC Conference Calls

1.1.30.6.5.1. Daily Area Control Room Coordination Conference Calls

Each morning, the NPCC Reliability Coordinator control rooms, NPCC Staff, and the Midcontinent MISOISO and PJM, take part in a regularly scheduled conference call. The goal of this call is to alert all neighboring Reliability Coordinators of any potential emerging problems which could lead to reliability concerns in the course of the day’s operations.

Subjects for discussion are limited to credible events which could impact the ability of a Reliability Coordinator to serve its load and meet its operating reserve obligations, or which would impose a burden to the neighboring NPCC Areas or the Eastern Interconnection.

1.1.31.6.5.2. Weekly Conference Calls

NPCC Staff convenes weekly conference calls to discuss expected operating conditions for the coming 710-day period. PJM and MISO also participate in these conference calls.

1.1.32.6.5.3. Emergency Conference Calls

NPCC has procedures in place to initiate an "Emergency Preparedness Conference Call" among the RCs of NPCC and NPCC Staff to discuss issues related to the adequacy and security of the interconnected bulk power supply system of the Northeast Power Coordinating Councilwhenever one or more Reliability Coordinators feel it would mitigate or prevent an emergency. The Midcontinent ISO and PJM also participate, as needed.

6.7.Reliability ApplicationsELIABILITY APPLICATIONS

1.23.7.1. Analysis Tools

Each Reliability Coordinator has adequate analysis tools such as state estimation, pre- and post-contingency analysis capabilities (thermal, stability, and voltage), and Wide Area overview displays as required for maintaining BPS reliable operations.

1.24.7.2. Communication Facilities

Each Reliability Coordinator maintains adequate communications facilities (voice and data links) to appropriate entities within its Reliability Coordinator


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Area. These communications facilities are staffed and available to act in addressing a real-time emergency condition.

1.25.7.3. Real Time Monitoring


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Real Time Monitoring

Each Reliability Coordinator continuously monitors its Reliability Coordinator Area. Each Reliability Coordinator has provisions for backup facilities that are utilized if the main monitoring system is unavailable. Each Reliability Coordinator ensures that SOL and IROL monitoring and calculations continue if the main monitoring system is unavailable.

7.8. Staffing and TrainingTAFFING AND TRAINING

1.26.8.1. Reliability Coordinator Staffing Requirements

The Reliability Coordinator is staffed with adequately trained and NERC-Certified Reliability Coordinator operators, 24 hours/day, seven days/week.

1.27.8.2. Certification


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Certification

Each Transmission Operator, Balancing Authority, and Reliability Coordinator staffs all operating positions that meet either one or both of the following criteria with personnel that are NERC-certified for the applicable functions:

• Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected BPS.

• Positions directly responsible for complying with NERC standards. While in training, an individual without the proper NERC certification credential may not independently fill a required operating position. Trainees may perform critical tasks only under the direct, continuous supervision and observation of the NERC certified individual filling the required position.

1.28.8.3. Staff Expertise

Reliability Coordinator operating personnel have an extensive understanding of the Balancing Authorities, Transmission Operators, and Generation Operators within the Reliability Coordinator Area, including the operating staff, operating practices and procedures, restoration priorities and objectives, outage plans, equipment capabilities, and operational restrictions.

1.29.8.4. Training

1.1.33.8.4.1. Training Requirements

All Reliability Coordinators, Transmission Operators and Balancing Authorities provide their System Operators with a coordinated training program that is designed to promote the reliable operation of the BPS. This program includes objectives based on the NERC Standards and NPCC documentation.

8.9.NPCC Operating Considerations


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NPCC Operating Considerations

9.1. ISO-NE

a) Is the Reliability Coordinator for the New England Area. b) Has the coordination responsibility to provide interconnection

protection against large source contingencies in ISO-NE. c) The ISO-NE reliability role is to limit the magnitude of the

contingencies noted above to levels which will not result in exceedance of NYISO and PJM (RF) operating criteria and will not jeopardize the reliability of the BPS. ISO-NE is responsible to control the size of these potential contingencies to achieve this objective. If necessary, ISO-NE will reduce imports on Phase II HVdc or order reduction of generation.

9.2. NYISO

a) Is the Reliability Coordinator for the New York Area. b) Is the coordinator for “Simultaneous Activation of Reserve” (SAR). c) Interacts closely with PJM and IESO to monitor and control parallel

flow effects on the Michigan-Ontario, New York–Ontario, and New York-PJM flowgates as well as NY’s internal interfaces (such as West CentralDysinger East and Central East) which may be impacted by Lake Erie circulation.


a) Is the Reliability Coordinator for the New York Area.

b) Is the coordinator for “Simultaneous Activation of Reserve” (SAR).

c) Interacts closely with PJM and IESO to monitor and control parallel flow effects on the Michigan-Ontario, New York–Ontario, and New York-PJM flowgates as well as NY’s internal interfaces (such as West Central and Central East) which may be impacted by Lake Erie circulation.


9.3. The Independent Electricity System Operator (IESO)

a) Is the Reliability Coordinator for the Ontario Area. b) Interacts closely with NYISO, MISO and PJM to monitor and control

parallel flow effects on the Michigan – Ontario, New York – Ontario, and New York – PJM flowgates as well as Ontario’s internal


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flowgates (such as Queenstown Flow West and Bruce Longwood Input) which may be impacted by Lake Erie circulation.


a) Is the Reliability Coordinator for the Ontario Area.

b) Interacts closely with NYISO, MISO and PJM to monitor and control parallel flow effects on the Michigan – Ontario, New York – Ontario, and New York – PJM flowgates as well as Ontario’s internal flowgates (such as Queenstown Flow West and Bruce Longwood Input) which may be impacted by Lake Erie circulation


9.4. System Control Department (Direction Contrôle des mouvements d’énergie), Hydro-Québec TransÉnergie

a) Is the Reliability Coordinator for the Québec Interconnection. b) Is connected to the BPS through DC facilities only and selected

isolated generation or isolated load. c) Coordinates operations with NYISO, ISO-NE, IESO and the

Maritimes.

a) Is the Reliability Coordinator for the Québec Interconnection.

b) Is connected to the BPS thru DC facilities only and selected isolated generation or isolated load.

c) Coordinates operations with NYISO, ISO-NE, IESO and the Maritimes. 9.5. New Brunswick Power – System Operator (NBP-SO)

a) Is the Reliability Coordinator for the Maritimes Area. b) Coordinates operations with ISO-NE through its synchronous ties to

the Eastern Interconnection, and with HQT through DC facilities. c) The NBP-SO serves as the Reliability Coordinator for New

Brunswick Power, Nova Scotia Power Incorporated, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The NBP-SO serves as the Balancing Authority for New Brunswick Power, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative are not part of the Bulk Power System.


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a) Is the Reliability Coordinator for the Maritimes Area.

b) Coordinates operations with ISO-NE through its synchronous ties to the Eastern Interconnection, and with HQT through DC facilities.

c) The NBPower NBP-SO serves as the Reliability Coordinator for New Brunswick Power, Nova Scotia Power Incorporated, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The NBPower NBP-SO serves as the Balancing Authority for New Brunswick Power, the province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative. The province of Prince Edward Island, Maine Public Service Company and the Eastern Maine Electric Cooperative are not part of the Bulk Power System.

1.30.9.6. Descriptions of Specific Operating Considerations

1.1.34.9.6.1. Central-East Interface (NYISO)

This interface consists of two 345 kV, two 230 kV and three 115 kVnumerous transmission lines in Mohawk Valley region of upstate New York. Central –East tends to load in an easterly direction. Contingencies, such as large generation loss east of the interface can lead to voltage collapse or instability in the New York Area if the established limits are not respected. The Central-East interface is monitored by the NYISO and procedures are in place (NYISO Emergency Operations Manual) such that generation re-dispatch and/or curtailment of transactions or load shedding can be initiated by NYISO as required to maintain (or regain) a safe margin on the interface. In addition to NYISO, the impact of these changes can involve IESO, ISO-NE, HQT and/or PJM depending on conditions in effect at the time.

1.1.35.9.6.2. Hydro-Québec TransÉnergie Phase II HVdc Exports

The Phase II Exports to ISO‐NE are monitored by ISO‐NE to ensure that interface or voltage limits ranging from the west of PJM through NYISO will not be violated. Using real-time data from both PJM and NYISO, ISO-NE coordinates with the Québec Reliability Coordinator the maximum allowable exports from HQT on Phase II in order to maintain the interconnected system in a secure operating state (as per ISO-NE Transmission Operating Guides “Procedure to Protect for the Loss of Phase II Imports”).

1.1.36.9.6.3. Maritimes Area-New England Minimum Tie Flow

During facility out conditions, within the NBP-SO or ISO-NE areas, the 345 kV interface from northern New England to the Maritimes Area may require that minimum export levels be maintained from


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the Maritimes Area in order to avoid stability and voltage problems in both Areas following large source contingencies in the Maritimes Area. The amount of power flow required is dynamically monitored by ISO-NE and NBPower. TheNBP-SO. The minimum tie flow limits calculated flows are based on a number of variables including: the element that is out of service, size of the largest Maritimes Area source contingency, generator dispatch in Maine, Generator and Madawaska HVDC dispatch in NB, Status of the Lepreau Nuclear Generating StationISO-NE load level, status of the Chester SVC, status of the Coopers Mills STATCOM, status of the Dogtown SVC, and status of Orrington Series CapacitorCapacitors and New England capacitor banks.

1.1.37.9.6.4. New Brunswick – Nova Scotia Interconnection Controlled Separation and Under Frequency Load Shedding

The province of Nova Scotia (NS) is radially connected to the Eastern Interconnection through synchronous ties with New Brunswick. (NB). During heavy interface flows from NB to NS, a single contingency will initiate a controlled separation of Nova ScotiaNS from NB and the Eastern Interconnection. Upon separation, the generation deficiency in Nova Scotia may be significant enough for NS to experience frequency decline to the point of triggering the first and possibly second stage of under frequency load shedding. The risk associated with separation and under frequency load shedding has been deemed acceptable to the province of Nova ScotiaNS. The separation of Nova ScotiaNS and the potential for under frequency load shedding does not have a significant adverse impact on the Eastern Interconnection as the loss of load due to controlled separation of NS is taken into consideration for all planning and operational studies within the Maritimes Area.

10. Plan Updates and Changes


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It is recommended that Tthis reliability plan will be reviewed every three years for changes. The plan should be updated, re-coordinated and re-endorsed by the NERC Operating ReliabilityReal Time Operating Subcommittee (RTOORS) for significant changes to the way NPCC RCs plan to meet the functional requirements.

Changes to the plan that would initiate an off-cycle update, re-coordination and re-endorsement can include but are not limited to:

• Significant changes to RC footprint BAs or TOPs (excluding new pseudo-ties) • Significant changes to RC congestion management processes • Changes that could have a significant impact on neighboring entities


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Appendix A - Agreements with External Entities

1. Coordination Agreements: • ISO-NE:

i. Coordination Agreement between ISO-NE and NBP-SO ii. Coordination Agreement between ISO-NE and NYISO

iii. Interconnections Operators Agreement between ISO-NE and HQ • NYISO:

i. NYISO Joint Operating Agreements with neighboring RCs • NBP-SO:

i. Interconnection Operators Agreement between NBP-SO and HQ-TransÉnergie

ii. Coordination Agreement between ISO-NE and NBP-SO • IESO:

i. Ontario IESO interconnection agreements with neighbouring RCs (NY-ISO, HQ-TE, MISO)

• HQ-TE: i. Common Instructions between Hydro-Quebec TransÉnergie and

IESO ii. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and NBP-SO iii. Communications Instructions for Hydro-Quebec TransÉnergie and

NYISO iv. Common Instructions between Hydro-Quebec TransÉnergie and

ISO-NE v. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and Velco. vi. Common System Operating Instructions between Hydro-Quebec

TransÉnergie and NYPA vii. Common System Dispatch Instructions between Hydro-Quebec

TransÉnergie and ISO-NE viii. Common System Dispatch Instructions between Hydro-Quebec

TransÉnergie and ISO-NE ix. Common Operating Instructions for Niagara Mohawk Power

Corporation, d/b/a National Grid.


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Real Time Operating Subcommittee Scope Purpose The Real Time Operating Subcommittee (RTOS) assists the NERC Reliability and Security Technical Committee (RSTC) in enhancing Bulk Electric System (BES) reliability by providing operational guidance to the industry; by providing oversight to the management of NERC-sponsored information technology tools and services which support operational coordination and by providing technical support and advice as requested.

Functions The RTOS will:

1. Develop and review reliability and security guidelines, and programs as directed by the RSTC tofacilitate operating reliability coordination. Included among the processes supported by RTOSare those related to:

a. Real-time communications among registered entities, especially Reliability Coordinators (RCs).

b. Exchange of operational data and modeling data among registered entities.

2. Disseminate operational information among the RCs and other reliability entities.

3. Respond to requests for technical input and guidance from the RSTC.

a. Maintain documents and guides created by the RTOS for the RSTC.

4. Review reliability plans and provide recommendations to the RSTC.

5. Provide a forum for coordinating system operating procedures in all four Interconnections,including:

a. Coordinate operating Reliability Standard implementation to promote consistency across theInterconnections.

b. Prepare for the upcoming operating peak demand season.

c. Review significant system disturbances and abnormal transaction curtailments, or others asrequested by RTOS, for "lessons learned".

d. Review Interconnection frequency events at each meeting.

6. Provide coordination between EIDSN, Inc. and the RSTC regarding the applications managed byEIDSN, Inc.

7. Provide a forum for coordination of TLR business practices and Reliability Standards.

8. Provide oversight and guidance on aspects of interchange scheduling, including dynamictransfers, as it applies to impacts on reliable operations.

2 Real Time Opearting Subcommitee Scope Approved by the Reliability and Security Technical Committee on December 15, 2020

Working Groups Working groups may include, and are not limited to, the following:

• Synchronous Measurement Working Group

Deliverables • Provide subcommittee report for the regularly scheduled RSTC meetings.

• Endorse or approve as applicable revisions to Reliability Plans.

• Develop comments on the annual State of Reliability report.

• Develop comments on Adequate Level of Reliability metrics.

• Develop recommendations to the RSTC on reliability guidelines.

• Develop responses to other directives and requests of the RSTC.

Reporting The RTOS reports to the RSTC and shall maintain communications with the RSTC and other groups as necessary on relevant issues.

Officers The NERC RSTC Chair appoints the RTOS officers (Chair and Vice Chair) for a specific term (generally two years). The subcommittee officers may be reappointed, provided that no officer may serve longer than two consecutive terms. The RTOS officers are considered members of the subcommittee and may vote. The RTOS may recommend officer candidates for the RSTC Chair’s consideration following a supporting motion. Both officers must be RC representatives.

Membership 1. One member from each RC.

2. Up to one additional non-RC member from each Region.

3. No single company may have multiple non-RC members

4. Current non-RC RTOS members will be grandfathered as a member of the subcommittee and thesubcommittee roster will indicate this grandfathered status

5. Once the current grandfathered members resign their position on the subcommittee the RTOSwill then accept applications for non-RC membership based on the criteria in number two above.The selection process will be determined by the RTOS.

As outlined in the RSTC’s “Subcommittee Organization and Procedures,” the RTOS shall have sufficient expertise and diversity to be able to speak knowledgably for the industry and provide meaningful and useful guidance to assist the industry in the carrying out of its reliability responsibilities.


Executive Committee The Executive Committee of the RTOS is empowered by the RTOS to act on its behalf between subcommittee meetings on matters where urgent actions are crucial and full subcommittee discussion is not practical. Ultimate RTOS responsibility resides with its full membership whose decisions cannot be overturned by the Executive Committee, but retains the authority to ratify, modify or annul Executive Committee actions. The Executive Committee will be comprised of the RTOS Chair, Vice Chair, along with three at large members. The Executive Committee members are elected by the RTOS for a two year term. The Executive Committee members may be re-elected.

Meeting Procedures 1. Quorum: 50 percent of subcommittee members eligible to vote

2. All other procedures follow those of the "Organization and Procedures Manual for the NERCStanding Committees."

Confidential Sessions The chairman of the subcommittee may limit attendance at a meeting or portion of a meeting, based on confidentiality of the information to be disclosed at the meeting. Such limitations should be applied sparingly and on a non-discriminatory basis as needed to protect information that is sensitive to one or more parties.

Example: The Reliability Coordinators may hold meetings in closed session when discussing reliability issues that they deem security, compliance, or commercially sensitive.

Subgroups The RTOS may form working groups, task groups, and task forces as needed to assist the subcommittee in carrying out standing or ad hoc assignments. Task group chairs (or delegates) are expected to attend the regular subcommittee meetings to report on assignments or provide a summary report of the group’s activities at a minimum.


Real Time Operating Subcommittee Scope Purpose The Real Time Operating Subcommittee (RTOS) assists the NERC Reliability and Security Technical Committee (RSTC) in enhancing Bulk Electric System (BES) reliability by providing operational guidance to the industry; by providing oversight to the management of NERC-sponsored information technology tools and services which support operational coordination and by providing technical support and advice as requested.

Functions The RTOS will:

1. Develop and review reliability and security guidelines, and programs as directed by the RSTC tofacilitate operating reliability coordination. Included among the processes supported by RTOSare those related to:

a. Real-time communications among registered entities, especially Reliability Coordinators (RCs).

b. Exchange of operational data and modeling data among registered entities.

2. Disseminate operational information among the RCs and other reliability entities.

3. Respond to requests for technical input and guidance from the RSTC.

a. Maintain documents and guides created by the RTOS for the RSTC.

4. Review reliability plans and provide recommendations to the RSTC.

5. Provide a forum for coordinating system operating procedures in all four Interconnections,including:

a. Coordinate operating Reliability Standard implementation to promote consistency across theInterconnections.

b. Prepare for the upcoming operating peak demand season.

c. Review significant system disturbances and abnormal transaction curtailments, or others asrequested by RTOS, for "lessons learned".

d. Review Interconnection frequency events at each meeting.

6. Provide coordination between EIDSN, Inc. and the RSTC regarding the applications managed byEIDSN, Inc.

7. Provide a forum for coordination of TLR business practices and Reliability Standards.

8. Provide oversight and guidance on aspects of interchange scheduling, including dynamictransfers, as it applies to impacts on reliable operations.


Working Groups Working groups may include, and are not limited to, the following:

• Synchronous Measurement Working Group

Deliverables • Provide subcommittee report for the regularly scheduled RSTC meetings.

• Endorse or approve as applicable revisions to Reliability Plans.

• Develop comments on the annual State of Reliability report.

• Develop comments on Adequate Level of Reliability metrics.

• Develop recommendations to the RSTC on reliability guidelines.

• Develop responses to other directives and requests of the RSTC.

Reporting The RTOS reports to the RSTC and shall maintain communications with the RSTC and other groups as necessary on relevant issues.

Officers The NERC RSTC Chair appoints the RTOS officers (Chair and Vice Chair) for a specific term (generally two years). The subcommittee officers may be reappointed, provided that no officer may serve longer than two consecutive terms for additional terms. The RTOS officers are considered members of the subcommittee and may vote. The RTOS may recommend officer candidates for the RSTC Chair’s consideration following a supporting motion. Both officers must be RC representatives.

Membership 1. One member from each RC.

2. Up to one additional non-RC member from each Region.

3. No single company may have multiple non-RC members

4. Current non-RC RTOS members will be grandfathered as a member of the subcommittee and thesubcommittee roster will indicate this grandfathered status

5. Once the current grandfathered members resign their position on the subcommittee the RTOSwill then accept applications for non-RC membership based on the criteria in number two above.The selection process will be determined by the RTOS.

As outlined in the RSTC’s “Subcommittee Organization and Procedures,” the RTOS shall have sufficient expertise and diversity to be able to speak knowledgably for the industry and provide meaningful and useful guidance to assist the industry in the carrying out of its reliability responsibilities.


Executive Committee The Executive Committee of the RTOS is empowered by the RTOS to act on its behalf between subcommittee meetings on matters where urgent actions are crucial and full subcommittee discussion is not practical. Ultimate RTOS responsibility resides with its full membership whose decisions cannot be overturned by the Executive Committee, but retains the authority to ratify, modify or annul Executive Committee actions. The Executive Committee will be comprised of the RTOS Chair, Vice Chair, along with three at large members. The Executive Committee members are elected by the RTOS for a two year term. The Executive Committee members may be re-elected.

Meeting Procedures 1. Quorum: 50 percent of subcommittee members eligible to vote

2. All other procedures follow those of the "Organization and Procedures Manual for the NERCStanding Committees."

Confidential Sessions The chairman of the subcommittee may limit attendance at a meeting or portion of a meeting, based on confidentiality of the information to be disclosed at the meeting. Such limitations should be applied sparingly and on a non-discriminatory basis as needed to protect information that is sensitive to one or more parties.

Example: The Reliability Coordinators may hold meetings in closed session when discussing reliability issues that they deem security, compliance, or commercially sensitive.

Subgroups The RTOS may form working groups, task groups, and task forces as needed to assist the subcommittee in carrying out standing or ad hoc assignments. Task group chairs (or delegates) are expected to attend the regular subcommittee meetings to report on assignments or provide a summary report of the group’s activities at a minimum.

Agenda Real Time Operating Subcommittee...2021/02/09 · a. Synchronized Measurement Working Group...

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