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Agenda Operating Reliability Subcommittee

May 7, 2019 | 1:00–5:00 p.m. Eastern May 8, 2019 | 8:00 a.m.–12:00 p.m. Eastern NERC Atlanta Office 3353 Peachtree Road NE Suite 600 – North Tower Atlanta, GA 30326 Dial-in Number + 1-415-655-0002 US Toll (Canadian Toll) + 1-416-915-8942 May 7, 2019: 734 993 347 | security code: 246810 | Join WebEx Meeting May 8, 2019: 732 343 828 | security code: 246810 | Join WebEx Meeting

Introductions and Chair’s Remarks

NERC Antitrust Compliance Guidelines and Public Announcement

Agenda

1. Administrative Matters

a. Arrangements, Safety Briefing and Identification of Exits – Darrell Moore

b. Announcement of Quorum – Secretary

i. Operating Reliability Subcommittee (ORS) Roster*

c. Parliamentary Procedures* – Secretary

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

e. Future Meetings – Secretary

i. September 4-5, 2019 – Audubon PA, (Hosted by PJM)

ii. November 6-7, 2019 Raleigh NC, (Hosted by NCEMC)

iii. February 11-12, 2020 Tampa FL, (Hosted by FRCC)

iv. Schedule future meetings

2. Meeting Minutes* – Approve – Chair Devereaux

a. Minutes of Feb 12 – 13, 2019 Operating Reliability Subcommittee Meeting

3. Reliability Plans* Chair Devereaux

a. Periodic Review of Reliability Plans

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

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https://signin.webex.com/collabs/auth

Agenda – Operating Reliability Subcommittee Meeting – May 7-8, 2019 2

b. New or Revised Reliability Plans for Endorsement

i. MISO Reliability Plan* Mike McMullen

ii. TVA Reliability Plan* Terry Williams

iii. PJM Reliability Plan* Chris Pilong

iv. BC Hydro Reliability Plan* Asher Steed

4. Resources Subcommittee update to ORS – Tom Pruitt/Sandip Sharma

5. Nomination of ORS Vice Chair- Dave Devereaux

6. Executive Committee Membership/ORS Roster

7. Operating Committee (OC) 2019 work plan update* – Dave Devereaux/D. Moore

8. NERC OC update, 2019 ORS work plan* March ORS Update to OC*– Dave Devereaux

9. Operations Review* – All

a. Operations Review

b. Use of Proxy Flowgates

c. Energy Emergency Alert Level 3 – Three

i. MISO RC EEA3 (SPC RC)

10. Interconnection Frequency Monitoring*

a. Frequency Monitor Reports and Frequency Excursions

i. Eastern – Terry Williams

ii. ERCOT – Jimmy Hartmann

iii. Western –

iv. Quebec – Francis Monette

b. Review of Frequency Monitor Criteria – Chair Devereaux

11. Argonne natural gas visualization tool*- James Kavicky

12. Mountain West RC (SPP)* - Bryan Wood

13. California ISO RC Certification* - Tim Beach

14. NERC RC Hotline use for interconnection events- Tim Beach

15. British Columbia (BC) Hydro RC Update – Asher Steed

16. British Columbia (BC) Hydro system overview – Asher Steed

17. Western RCs certification status- Tim Reynolds

18. EPRI presentation on R&D project on high voltage* - Alberto Del Rosso

19. Time Error Document*- Raj Venkat

Agenda – Operating Reliability Subcommittee Meeting – May 7-8, 2019 3

20. Dynamic Transfer Document* Chris Pilong

21. RCIS postings and common practices/alignment – Chris Pilong

22. ORS/NERC Summer Assessment* - Mark Olson

23. Status Report of the EIDSN Association – Chris Wakefield

24. Round table open discussion all (Open) etc. - All

*Background materials included.

NERC Antitrust Compliance Guidelines I. General

It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between 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 Activities

Participants in NERC activities (including those of its committees and subgroups) should refrain from the following 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 cost information 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 among competitors.

Discussions concerning the exclusion of competitors from markets.

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

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

III. Activities That Are Permitted

From time to time decisions or actions of NERC (including those of its committees and subgroups) may have a negative impact on particular entities and thus in that sense adversely impact competition.

NERC Antitrust Compliance Guidelines 2

Decisions and actions by NERC (including its committees and subgroups) should only be undertaken for the purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If you do not have a legitimate purpose consistent with this objective for discussing a matter, please refrain from 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

Agenda Item 1.b.i ORS Meeting

May 7-8, 2019

Operating Reliability Subcommittee

Chair Dave Devereaux

Senior Manager Operations

Vice Chair Christopher Pilong

Director of Dispatch

Bryan Wood

Manager, System Operations

James E. Hartmann, Jr.

Senior Manager, Systems Operations

Richard W Kiess

Manager, Reliability Coordination

Richard McCall

Director, Environmental & Transmission Compliance

Michael McMullen

Director, Regional Operations Francis Monette,

Manager – System Scheduling and Operations

John R. Norden

Director, Operations Vince Ordax

Director of Operations

Donald E. Reichenbach Manager, System Operations Tim Reynolds Senior Reliability Engineer

Steven C. Sanders

Operations & Transmission Advisor

Lacy Skinner

Supervisor Control Center Operations Asher Steed Manager System Operations

Christopher A Wakefield

Reliability Coordination Manager Andy Pankratz Senior Manager, System Operations Terry Williams Manager Reliability Operations Raj Venkat Manager RC Operations

NERC Staff Stephen Crutchfield

Senior Manager of Operating Committee Support

Darrell Moore

Associate Director, Bulk Power System Awareness

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.

Agenda Item 1.c ORS Meeting

May 7-8, 2019

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 on e debated. The original “seconder” need not be consulted, because the original “motion-maker” plus the “reviser” constitute a motion and a second.

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Agenda Item 1.d ORS Meeting

May 7-8, 2019

1

NERC RELIABILITY COORDINATOR AREAS Effective: August 15, 2016

1

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

PEAK

SPP

HQT ONT

ISONE NYISO PJM

SOCO

TVA VACAR-S

FRCC

ERCOT

MISO

Future

NBPC

SPRC

AESO


May 7-8, 2019

2

NERC RELIABILITY COORDINATOR DESKS Effective: August 15, 2016

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 Same

ERCOT Same

PEAK (Loveland, Vancouver) Same

AESO RC2 Same

CAISO RC (Future) Same (Future) CAISO will become RC 7/1/2019

BC Hydro (Future) Same (Future) BC Hydro will become and RC 9/21/2019



May 7-8, 2019

3

NERC BALANCING AUTHORITY TO RELIABILITY COORDINATOR MAPPING

August 15, 2016 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

VACAR-S DUK SERC

SCEG SERC SC SERC CPLW SERC YAD SERC CPLE SERC

TVA LGEE SERC

TVA SERC AECI SERC EEI SERC

SOCO SOCO SERC SEPA SERC AEC SERC

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


May 7-8, 2019

4

Current Reliability

Coordinator

Balancing Authority


Future Reliability

Coordinator

Regional Entity


MISO MISO RF

MECS RF BREC SERC CIN RF HE RF IPL RF DECO RF NIPS RF SIGE RF AMIL SERC AMMO SERC CWLD SERC ALTE MRO ALTW MRO CWLP SERC MGE MRO SIPC SERC UPPC MRO MIUP RF WEC RF WPS MRO GRE MRO MDU MRO MEC MRO MP MRO MPW MRO NSP MRO OTP MRO CONS RF SMP MRO DPC MRO MHEB MRO EES SERC CLEC SPP LAFA SPP LEPA SPP LAGN SERC SME SERC

AESO3 AESO WECC PEAK GWA WECC

WAUW WECC AVA WECC



May 7-8, 2019

5

Current Reliability

Coordinator

Balancing Authority


Future Reliability

Coordinator

Regional Entity


BCTC WECC BPAT WECC CHPD WECC DOPD WECC GCPD WECC IPCO WECC NWMT WECC PGE WECC GRMA WECC PACW WECC PSEI WECC SCL WECC WWA WECC TPWR WECC PACE WECC TIDC WECC CISO WECC CEN WECC LDWP WECC SMUD WECC GRIF WECC AZPS WECC EPE WECC DEAA WECC IID WECC PNM WECC NEVP WECC PSCO WECC SRP WECC TEPC WECC WACM WECC WALC WECC HGMA WECC GRID WECC

SPRC SPC MRO ERCOT ERCO Texas RE SPP SWPP SPP

SPA SPP

Meeting Minutes Operating Reliability Subcommittee February 12-13, 2019 FRCC Offices 3000 Bayport Drive Tampa, FL Introductions and Chair’s Remarks The Operating Reliability Subcommittee (ORS) met on February 12-13, 2019 in Tampa FL. The meeting agenda and the attendance list are affixed as Exhibits A and B, respectively. NERC Antitrust Compliance Guidelines and Public Announcement ORS Chair Dave Devereaux convened the meeting at 1:00 p.m. Eastern. Secretary Darrell Moore announced that a quorum was present, read the Notice of Public Meeting and referred the Subcommittee to the NERC Antitrust Compliance Guidelines. Agenda Items

1. Meeting Minutes Review and Approval: The Subcommittee approved the minutes of the November 7-8, 2018 meeting. Don Reichenbach made a motion that the minutes be approved as amended with the necessary corrections.

2. Balancing Authority-to-Reliability Plans: No changes

3. Reliability Coordinator Reliability Plans: The ORS endorsed the MISO and CAISO Reliability Plans. BC Hydro is continuing to develop their draft plans. Once BC Hydro’s draft plans are developed, they will be shared with WECC and will be circulated with the ORS for review. The ORS will bring the CAISO and MISO plans before the Operating Committee (OC) during the March 2019 OC meeting in Pittsburg, PA.

a. MISO Reliability Plans are general clean up with no significant changes. The minor changes for MISO reflects a new Local Balancing Authority (LBA) within the MISO footprint. Henderson Municipal Power and Light is currently completing the registration process to begin LBA operation.

b. CAISO Reliability Plans are new and have been developed with the assistance of WECC, Peak RC and the ORS.

4. Resources Subcommittee (RS) update to ORS – Tom Pruitt provided an update on the RS and their activities to include status reports received, metrics reports reviewed, and document revisions. Tom also noted that the RS is working on BA Bubble Map update, GO Survey, 2019 SOR update and changes to BA Area footprints. The ORS and RS will be collaborating on combining several reference documents.

Meeting Minutes – Operating Reliability Subcommittee Meeting – February 12-13, 2019 2

5. OC 2019 work plan update – Darrell Moore/Dave Devereaux provided an update on the OC activities. The OC approved several reference documents and guidelines to include the Reliability Coordinator Reliability Plan Reference document, and the RS Scope document. The OC also retired several guidelines, discussed RC footprint changes, Mountain West, California ISO and Peak RC.

6. NERC OC update, 2019 ORS work plan December ORS Update to OC*– Dave Devereaux provided an update on the ORS work plan to include working with the RS on combining the Dynamic Transfer, Dynamic Tag and the Pseudo-Tie Reference Documents into a single reference document, the ORS will take the lead on the effort. Continue to monitor and review development of Western Interconnection RC Reliability Plans. Continue to support Grid Ex V and continue to monitor development of common tools and act as the point of contact for EIDSN.

7. 2019 OC Work Plan – assign review teams for documents coming due – Dave Devereaux assigned teams to review reference documents that are up for review. Continue to look at the A and B framework for the IROL. Review and update Time Error Correction document; Dynamic Transfer Reference document; Dynamic Tag Exclusion Reference document; Pseudo-Tie Coordination Reference document and summary document. Work with RS on combining Dynamic Transfer, Dynamic Tag Exclusion and Pseudo-Tie Reference documents.

8. Operations Review – All RC members of the Subcommittee discussed operating events that occurred within their reliability footprints during the winter months.

a. The Bulk Electric System (BES) performed well throughout the winter season, with no major issues. However, some RCs experienced colder than normal temperatures across their footprints.

b. Several RCs reported milder temperatures across their footprints during the winter months.

c. Several RCs implemented Conservative Operations and Cold Weather Alerts across their footprints during colder than normal temperatures.

d. Several RCs experienced above average rain across their footprints.

e. Some RCs experienced warmer than normal conditions.

9. USE of Proxy Flowgates: None

10. Energy Emergency Alert Level 3: Three

a. FRCC EEA3 (TECO) 1ea. (No firm load was shed)

b. Peak RC EEA3 (NV Energy) 1ea. (No firm load was shed)

c. HQT EEA3 1ea. (No firm load was shed)

11. Interconnection Frequency Monitoring

a. Eastern – Terry Williams: See presentation related to January 11 oscillation occurrence.

b. ERCOT – Jimmy Hartmann: Nothing to report

c. Western – Nothing to report


d. Quebec – Francis Monette: Nothing to report

12. Mountain West RC (SPP) – Bryan Wood provided an update on the SPP RC preparations for their Mountain West area. Continuing to hire RC operators, and working with CAISO and Peak RC on transition. December 3, 2019 is the planned go-live date.

13. California ISO RC Certification – Tim Beach working on RC communication plan for coordinating messages and monitoring. CAISO is continuing to work with the western RCs on the RC transition plan. Continuing to develop tools for wide area monitoring. CAISO submitted their Reliability Coordinator Reliability Reference Plan to the ORS for endorsement. The ORS endorsed the CAISO Reliability Plan and will submit it to the OC for endorsement during the March OC meeting.

14. Hurricane Michael – Chris Wakefield provided an update on Hurricane Michael and its impacts in the Southeastern Reliability Coordinator (SeRC) footprint. Hurricane Michael made landfall on October 10, 2018. Michael was the first Category 4 storm in recorded history to make landfall in the Florida Panhandle. Chris discussed some of the lessons learned and operating actions taken pre and post Hurricane Michael.

15. NERC Electric/Gas Working Group (EGWG) – Thomas Coleman provided an overview of the EGWG. The EGWG is under the Planning Committee (PC) and has been tasked with conducting studies around natural pipeline infrastructure and the loss of natural gas pipelines. They are also looking at coal plant retirements and the increase of natural gas generation replacing retiring plants. Tom gave an overview of the group’s objectives related to fuel assurance. The group will be conducting outreach for participants that are interested in collaborating with the working group.

16. RCIS postings and common practices/alignment – Chris Pilong provided an update on PJM’s requirements for posting events on RCIS. Suggested that ORS members look at their internal procedures and revisit posting policies. Working toward looking at the consistency of RCIS postings across the RCs.

17. FRCC Hotline (VOIP) experience – Vince Ordax provided an update on FRCC RC hotline and the features and options provided. Several RCs are using VOIP and are very pleased with its performance.

18. NERC RC Hotline – Darrell Moore provided an update on the NERC RC Hotline issue on January 11, 2019. NERC BPSA has a plan in place to manage the Hotline for future issues such as the one that occurred on January 11, 2019.

19. BC Hydro RC update – Asher Steed provided an update on BC Hydro service territory. BC Hydro is currently receiving RC services from Peak RC. BC Hydro is in the process of becoming an RC. Asher provided an update on the plans and processes they are currently using. The goal is to become a RC of record on September 2, 2019 and currently working with WECC on the RC certification process. BC Hydro is currently regulated by the BC Utilities Commission. BC Hydro will be moving into shadow operations in July for eight weeks. BC Hydro is continuing to work on tools development for the wide area RC services. They are also drafting their RC Reliability Plan and will submit it for ORS review upon completion.


20. January 11 Frequency Event – Tim Fritch vice chair of System Analytics and Modeling Subcommittee (SAMS) provided a presentation on the January 11, 2019 forced oscillation event analysis. Tim included an overview of the tools used and the entities that provided data to the working group to complete the analysis. Tim also noted that the working group is in the process of finalizing an oscillation report that will be submitted to the PC during the March PC meeting. Currently, the report is in draft form.

The ORS also discussed the frequency event from a communications and coordination perspective. Several members felt that the joint ORS/RS call that was held on January 12 was valuable and should be explored as a model for future events. John Norden offered to provide some criteria that could guide the possible development of a protocol.

21. ORS/NERC Summer Assessment – Mark Olson provided a presentation on the 2019 Summer Reliability Assessment (SRA). Mark noted that the Reliability Assessments Subcommittee (RAS) will enhance the 2019 SRA by including seasonal risk scenarios. The goals is for the scenarios to provide more accurate view of summer reliability risks than planning reserve margins alone. Mark provided examples of Seasonal Risk Scenarios, and narrative guide questions.

22. Status Report of the EIDSN Association (NAESB PFV Status Report) – Chris Wakefield provided an overview on the Parallel Flow Visualization (PFV) tool. The PFV project is intended to improve the data quality used by the IDC during curtailment of transactions and may eventually result in changes to both NERC Reliability Standards and NAESB Business Practices. The 12-18-month field trial is still running. The field trial began in September 2017. The IDCWG continues to provide updates to the ORS during the field trial, and the WG feels that the PFV should be ready for OC approval in 2019.

23. Round table open discussion all (day ahead Operating Plan) etc. – The group discussed day ahead planning across the RCs and some of the day ahead planning activities within the various RC control rooms.

Adjourn There being no further business before the Operating Reliability Subcommittee, Chair Devereaux adjourned the meeting on Wednesday, February 13, 2019 at 11:00 a.m. EST.

Darrell Moore Darrell Moore Secretary

- 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 ORSMeeting May

7-8, 2019

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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.



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.



Approval Process Flow Chart

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

ORSEndorsesApproval

ORSReviews Plan

ORSPresents plan to OC

Recommends ApprovalWith Starup Predicated on

Evaluation Results Satisfactory to ORS

OC Approves Plan

Yes

NERCProvides Access

toIDC, SDX, RCIS

RC/Prospective RC

Re-Submits Reliability Plan to

ORS

ORSSpecifies Changes

NoRC/PRCRevises Plan

OCSpecifies Changes

No

NERCPerforms

Evaluation

ORSReviews Results

EvaluationOK ?

ORSApproves

RC Start up

ORSInforms

OC

Yes

ORSSpecifies Mitigating Measures

No

RC/PRCImplementsMitigating Measures

RC/PRCPresents

CompletedMitigating MeasuresTo ORS

ORSAccepts

SecondEvaluationRequired?

Yes

No

NoYes

Yes

If EvaluationIs Needed

The Operating Committee (OC) and Operating Reliability Subcommittee (ORS) shall follow the process flow diagram detailed below when reviewing a Regional Reliability Organization Reliability Plan or a Reliability Coordinator Reliability Plan.

British Columbia Reliability Coordinator (BCRC) Reliability Plan Revision 0.13 April 17, 2019

Contents Introduction .................................................................................................................................... 2

A. Responsibilities – Authorization .............................................................................................. 3

B. Responsibilities – Delegation of Tasks ..................................................................................... 4

C. Common Tasks for Next-Day and Current-Day Operations .................................................... 5

D. Next Day Operations ............................................................................................................... 7

E. Current Day Operations ........................................................................................................... 8

F. Emergency Operations .......................................................................................................... 13

G. System Restoration ................................................................................................................ 14

H. Coordination Agreements and Data Sharing ......................................................................... 15

I. Facility .................................................................................................................................... 16

J. Staffing ................................................................................................................................... 18

Appendix A – BCRC Governing Documents .................................................................................. 19

Agenda Item 3b.ivORS MeetingMay 7-8, 2019

Introduction The North American Electric Reliability Corporation (NERC) Standards require every Regional Reliability Organization (RRO), subregion, or interregional coordinating group to establish a Reliability Coordinator to continually assess transmission reliability and coordinate emergency operations among the operating entities within the region and across the regional boundaries. BC Hydro and Power Authority serves as both the Reliability Coordinator and the Balancing Authority for the Province of British Columbia, within the Western Electricity Coordinating Council. The Reliability Coordinator functions are under the functional authority of the Manager, Provincial Reliability Coordination Operations, who reports to the Director of Transmission and Distribution System Operations. The department performing the Reliability Coordinator functions is referred to as the British Columbia Reliability Coordinator or BCRC. The BCRC reliability area is defined as the physical footprint of the province of British Columbia. The BCRC is recognized as the RC for the BC Hydro Balancing Authority and for the following Transmission Operators: BC Hydro, FortisBC and Teck Metals Ltd. British Columbia is synchronously interconnected to the Province of Alberta and to the State of Washington. BC Hydro has established a Reliability Coordinator Standards of Conduct ensuring functional separation and independence, and aligning the transmission activities, planning, and operations to NERC and FERC standards. All power marketing activities are carried out by BC Hydro’s wholly owned subsidiary, Powerex Corp. which exists in a separate headquarters than the BC Hydro Control Centres. The BCRC is responsible for the bulk transmission reliability and power supply reliability within its Reliability Coordination Area. Bulk transmission reliability functions include assessment of real-time, current day and next-day operating conditions, loading relief procedures, re-dispatch of generation, coordination of transmission and generation outages and ordering curtailment of transactions and/or load. Power supply reliability entails monitoring Balancing Authority Area performance and ordering the Balancing Authority to take actions, including load curtailment and increasing/decreasing generation in situations where an imbalance between generation and load places the system in jeopardy. BCRC policies and procedures are consistent with those of the B.C. Mandatory Reliability Standards (MRS). The BCRC authorized personnel have the authority to approve or cancel planned transmission and power supply outages (including those to the telecommunication system, monitoring and analysis capabilities).

A. Responsibilities – Authorization Reliable Operations – The British Columbia Utilities Commission, through [TBD - Applicable BCUC order], has granted the BCRC with the authority to act as necessary to support and maintain the reliable operation of the bulk electric system of B.C. and the Western Interconnection. Through the authority granted by [TBD - Applicable BCUC order], the BC Reliability Coordinator (BCRC) has the responsibility and authority to act to address the reliability of the RC area, in both real-time and next-day operations, by issuing Operating Instructions to the B.C. MRS Registered Entities to take actions up to and including shedding firm load. The BCRC authorized personnel have the responsibility and authority to direct these actions without obtaining prior approval from higher level personnel within BC Hydro. The BCRC has a wide-area view, operating tools, processes and procedures and the authority given by [TBD - Applicable BCUC order], to prevent or mitigate emergency operating situations in real-time, current-day operations, and next-day operations. More detail is provided in appropriate sections of this document. The BCRC has clear decision-making authority to act and to direct actions to be taken by B.C MRS Registered Entities within its Reliability Coordination Area to preserve the integrity and reliability of the Bulk Electric System. The BCRC responsibilities and authorities are clearly defined in the governing documents. The BCRC has not delegated any of its Reliability Coordinator responsibilities. Independence – The BCRC, as the Reliability Coordinator for the B.C. Balancing Authority Area, does and will act first and foremost in the best interest of its Reliability Coordination Area and the Western Interconnection before that of any other entity. The expectation of independence is clearly identified in the governing documents included in Appendix A. BCRC Operating Instruction Compliance – As indicated in [TBD - Applicable BCUC order], the B.C. MRS Registered Entities in the BCRC area are obligated to comply with the BCRC Operating Instructions, unless such actions cannot be physically implemented or will violate safety, equipment, regulatory, or statutory requirements. Under these circumstances, the entity shall, without delay, inform the BCRC authorized personnel of the inability to perform the instruction, so that the BCRC authorized personnel may implement alternate actions.

B. Responsibilities – Delegation of Tasks The BCRC has not delegated any of its Reliability Coordinator responsibilities.

C. Common Tasks for Next-Day and Current-Day Operations This section documents how the BCRC conducts current-day and next-day reliability analysis for its Reliability Coordination Area.

1. Determination of Interconnection Reliability Operating Limits (IROLs) – The BCRC has a System Operating Limits Methodology for the operation horizon which includes establishing and communicating IROLs. The RC will determine the need for establishing IROLs based on studies performed one or more days prior to real-time that identify instability, Cascading or uncontrolled separation affecting an undetermined area or a wide area of the system. Presently, there are no IROLs identified in the BCRC Area. When establishing IROLs, the BCRC will coordinate with impacted entities to develop an Operating plan that identifies facilities that are critical to the derivation of the IROL, the value of the IROL and its associated Tv, the associated contingencies, and to ensure that all entities understand their role in the plan.

2. Operation to prevent the likelihood of a SOL or IROL exceedance in another area of

the Interconnection and operation when there is a difference in limits - The BCRC, through agreements with its RC neighbours, coordinates operations to prevent the likelihood of an SOL or IROL exceedance in another area. These agreements include data exchange to support the reliable operation of the Interconnection as described in Section H.

TOPs in the BCRC Area are required to follow operating instructions provided by the BCRC per BC MRS and operate to BC MRS to prevent the likelihood that a disturbance, action, or non-action in its Reliability Coordination Area will result in an SOL or IROL exceedance in another area of the Interconnection. When there is a difference in derived limits, the BCRC utilizes the most conservative limit until the difference is resolved.

3. Operation under known and studied conditions and re-posturing without delay and no

longer than 30 minutes - The BCRC ensures that entities within its RC Area always operate under known and studied conditions and that they return their systems to a secure operating state following contingency events within approved timelines, regardless of the number of contingency events that occur or the status of their monitoring, operating and analysis tools. The BCRC also ensures its BA and TOPs re-posture the system to within all IROLs following contingencies within Tv or 30 minutes, whichever is shorter. On a daily basis, the BCRC conducts next business day Operational Planning Analyses utilizing planned outages, forecasted loads, generation commitment, and expected net interchange. The analyses include contingency analysis, voltage security analysis on key interfaces. These analyses model peak conditions for the day and are conducted utilizing Single Contingency (N-1) as well as credible Multiple Contingency analysis. The OPA

considers Operating Plans developed by BA and TOPs, and the BCRC will ensure that these plans get revised with additional mitigation actions as needed for potential exceedances determined in the next-day operational planning analysis. Results and mitigation are documented in the Next-Day Operational Planning Analysis Report (OPA) and distributed to BCRC Reliability staff.

The BCRC OPA Report is posted on the BCRC Extranet secure web site for the BA and TOPs in the BCRC Reliability Coordination Area and neighbours to view and download. The BCRC OPA report includes significant generation outages, significant line outages, projected constraints, load forecast, generation unit commitments, and interchange schedules. The BCRC DOP is reviewed each weekday morning with TOPs, the BC Hydro BA, and neighbouring RCs where expected system conditions for the day are discussed, along with action required to mitigate any abnormal conditions. Additional conference calls are conducted with the same group when conditions warrant.

4. Communicating SOLs and IROLs – The BCRC monitors BES Facilities, the status of

Remedial Action Schemes, and non-BES facilities identified as necessary by the BCRC, within its Reliability Coordinator Area and neighbouring Reliability Coordinator Areas to identify any SOL exceedances and to determine any IROL Limit exceedances within its Reliability Coordinator Area. The RC Operator is able to monitor the reliability and security of the BCRC Area through the monitoring of pre-contingency SOL and IROL exceedances identified by EMS alarms and State Estimator, and monitoring post-contingency SOL and IROL exceedances identified by Contingency Analysis results. SOLs are established in the BCRC Area by Transmission Operators consistent with the BCRC’s System Operating Limit Methodology. The BCRC communicates IROLs within its wide-area view and provides updates to IROLs in reports, morning conference calls, and real-time via voice and messaging.

5. BCRC process for issuing operating instructions – The BCRC has implemented a

communication protocol for the issuing/receiving of operating instructions. The BCRC issues operating instructions in a clear, concise and definitive manner. The BCRC ensures that the person receiving the operating instruction repeats the information back correctly, and acknowledges the response as correct or repeats the original statement again to resolve any misunderstandings. The BCRC’s process for issuing operating instructions is documented in 8T-11 Communication Protocols procedure.

D. Next Day Operations This section documents how the BCRC conducts the next-day operational planning assessment (OPA) for its Reliability Coordination Area. Reliability Analysis and System Studies - The BCRC performs an OPA to assess planned operations for the next business day (and weekends/holidays that fall before the next business day) to ensure that the Bulk Power System can be operated reliably in pre- and post- contingency conditions. One study is typically performed for the entire BCRC Area. Each business day and more often as required, the BCRC performs an OPA including equipment outages, forecast loads, generation commitments, and expected net interchange. All facilities 100 kV and above and some non-BES facilities in the BCRC Area are monitored for all contingency cases and the base case. Base case flows on all monitored facilities are compared against their normal rating and pre-determined stability limits, and post-contingent flows for all monitored facilities are compared against their emergency rating. Voltage stability analysis is conducted on key critical interfaces to determine a flow limits. The OPA considers Operating Plans developed by BA and TOPs. The BCRC will ensure that these plans get revised with additional mitigation actions as needed for potential exceedances identified in the next-day operational planning analysis. The BCRC will communicate with impacted entities to address potential exceedances immediately as they are identified. Information Sharing – The BA, and TOPs in the BCRC Reliability Coordination Area and neighbouring RCs provide to the BCRC all information required for system studies, such as equipment outages, load forecast, generation unit commitments as per 8T-20 BCRC Data Specification and through data sharing agreements. The entities in the BCRC Reliability Coordination Area provide generation and transmission facility statuses per BCRC outage coordination requirements. BCRC Reliability Coordination Area load forecast is provided by the BC Hydro BA and is independently calculated in the BCRC EMS. Known interchange transactions involving the BCRC area are provided in the Western Interchange Tool (WIT). Sharing of Study Results - The BCRC shares the results of its next-Day OPA with BCRC Reliability staff, entities within its Reliability Coordination Area and with other RCs. Study results for the next day up to and including the next business day typically are available no later than 14:00 Pacific Prevailing Time, unless circumstances warrant otherwise. The next-Day OPA is distributed to BCRC Reliability staff and is posted on the BCRC Extranet secure website for the BA/TOPs in the BCRC Reliability Coordination Area and neighbouring RCs to view and download.

E. Current Day Operations This section documents how the RC conducts current-day reliability analysis for the RC area.

1. The BCRC uses a suite of real time network analysis tools to continuously monitor all Bulk Electric System (BES) and relevant Non-BES facilities within the BCRC Area and adjacent areas, as necessary, to ensure that the BCRC is able to determine any potential SOL and IROL violations within its Reliability Coordination Area.

The BCRC utilizes a state estimator, real-time contingency analysis and real-time voltage stability analysis as the primary tools to monitor facilities. The BCRC models all transmission elements in the BCRC Area operated at voltages greater than 25kV. The model also has extensive representation of neighbouring facilities in order to provide an effective wide-area view. The BC Hydro State Estimator Model currently includes over 8,000 buses. This model is typically updated weekly and may be updated on demand when deemed necessary. Real Time Contingency Analysis (RTCA) is performed on approximately 700 contingencies, defined by BCRC engineering staff, using the state estimator model approximately every 4 minutes. Contingencies include all BES equipment and critical 60kV facilities in the BCRC Area and neighbouring contingencies that would impact facilities located within the BCRC Area. The actions from Remedial Action Schemes modeled within the EMS are included when RTCA contingencies are applied. Real Time Voltage Stability Analysis (RTVSA) is performed on the 7 defined contingencies that make up the Interior-Lower Mainland path. RTVSA utilizes the most recent state estimator solution as its base case and provides updated results every 3-4 minutes. SCADA alarming and RTCA pre-contingency results is utilized to alert the BCRC of any actual low of high voltages or facilities loaded beyond their normal or emergency limits. In addition to the above applications, the BCRC uses several displays to maintain a wide area view for real-time and N-1 conditions. Transmission facilities assessed as critical are depicted on the e-terra vision overview for the BCRC Area and neighbouring areas. RTCA results as well as flows (MW and MVAR), indication of facilities out of service, and high/low voltage warning and alarming can be displayed on this overview. The RC Overview display monitors actual generation, frequency, and real and reactive reserves. The RC Voltage display monitors important substation voltages rated at 138kV and above. Substation one-line diagrams are used for station level monitoring and information.

3.1 As required by the RC to RC coordination agreements it has with its neighbouring

RCs, the BCRC will make reasonable efforts to provide notice to a neighbouring RC if the BCRC identifies an operational concern in that RC’s area (e.g. declining

voltages, excessive reactive flows, or an IROL exceedance). The BCRC directs action to provide emergency assistance to all Reliability Coordination neighbours, during declared emergencies, which is required to mitigate the operational concern to the extent that the same entities are taking in kind steps and the assistance would be effective.

2. The BCRC maintains awareness of the status of all current critical facilities whose failure,

degradation or disconnection could result in an SOL or IROL exceedance within its Reliability Coordination Area via State Estimator, RTCA, SCADA alarming, and transmission displays. The BCRC is aware of the status of any facilities that may be required to assist Reliability Coordination Area restoration objectives via these same displays and tools.

3. The BCRC is continuously aware of conditions within its Reliability Coordination Area

and includes this information in its reliability assessments via automatic updates to the state estimator, e-terra vision, and transmission displays. The BCRC monitors its Reliability Coordination Area parameters, including the following:

3.1 Current status of Bulk Electric System elements (including critical auxiliaries such

as Automatic Voltage Regulators), and system loading are monitored by state estimator, RTCA, SCADA Alarming, e-terra vision, and transmission displays. TOPs are required to report to the BCRC when Automatic Voltage Regulators are not in-service and when Remedial Action Schemes are not available or degraded or the corresponding teleprotection fails.

3.2 Current pre-contingency element conditions (voltage, thermal, or stability) are

monitored by state estimator, SCADA Alarming, e-terra vision, and transmission displays.

3.3 Current post-contingency element conditions (voltage, thermal, or stability) are

monitored by RTCA, e-terra vision and transmission displays.

3.4 System real reserves are monitored versus required on the RC Overview display. Reactive reserves versus required are monitored via monitoring adequacy of calculated post-contingent steady state voltages versus voltage limits, voltage stability interfaces against limits, and reactive reserves versus required when applicable.

3.5 Capacity and energy adequacy conditions - via monitoring reserve requirements

and regional reporting.

3.6 Current ACE for the Balancing Area is displayed in a trend graph to the BCRC. When ACE exceeds BAAL, the graph changes colour and alerts operator of magnitude of ACE and the duration ACE has exceeded BAAL.

3.7 Planned generation dispatches for the BCRC Area are provided to the BCRC in the

form of the unit commitment plan. 3.8 Planned transmission or generation outages are reported to the BCRC via the

Control Room Operating Window (CROW) application. 3.9 Contingency Events are monitored by state estimator, RTCA, SCADA Alarming, e-

terra vision, and transmission displays. The BA and TOPs are required to report Contingency Events to the BCRC.

4. The BCRC monitors Bulk Power System parameters that may have significant impacts

upon its Reliability Coordination Area and neighboring Reliability Coordination areas with respect to: 3.1 The BCRC maintains awareness of all Interchange Transactions that wheel-

through, source, or sink in its Reliability Coordination via NERC E-tags and OATI displays. Interchange Transaction information is made available to all RCs via NERC E-tags.

3.2 The BCRC evaluates and assesses any additional Interchange Transactions that would exceed IROL or SOLs by comparing current system conditions and limits to RTCA results. As flows approach their IROL or SOLs, the BCRC evaluates the incremental loading next-hour transactions would have on the SOLs or IROLs and determines if action needs to be taken to prevent an SOL or IROL exceedance. The BCRC has the authority to direct all actions necessary and may utilize all resources to address a potential or actual IROL exceedance up to and including load shedding.

3.3 The BCRC monitors the BC Balancing Area Operating Reserves versus required to ensure the required amount of Operating Reserves are provided and available as required to meet NERC Control Performance Standards. The BCRC is alerted if reserves fall below required. If necessary, the BCRC will direct the Balancing Area to replenish reserves including obtaining assistance from neighbours as needed.

3.4 The BCRC identifies the cause of potential or actual SOL or IROL exceedances via analysis of state estimator results, RTCA results, SCADA Alarming of outages, transmission displays of changes, and Interchange Transaction impacts. The BCRC will initiate control actions including transmission switching, generation redispatch, and/or emergency procedures to relieve the potential or actual IROL exceedance without delay, and no longer than 30 minutes. The BCRC is authorized to direct utilization of all resources, including load shedding, to address a potential or actual IROL exceedance.

3.5 The BCRC communicates start and end times for time error corrections to the Balancing Authority within its RC Area. The BCRC communicates Geo-Magnetic Disturbance forecast information to BAs, TOPs, and will assist in development of any required response plan. The BCRC uses a dedicated messaging system to communicate timer error correction and GMD forecast information to its Balancing Authority.

3.6 The BCRC participates in NERC Hotline discussions, assists in the assessment of reliability of the Regions and the overall interconnected system, and coordinates actions in anticipated or actual emergency situations. The BCRC will disseminate this information within its area as appropriate.

3.7 The BCRC monitors system frequency and its Balancing Authority’s performance and will direct any necessary rebalancing required for the BA to return to CPS and Disturbance Control Standard (DCS) compliance. The BCRC receives a visual indication when ACE exceeds BAAL and/or L10. When necessary, the BCRC directs the Balancing Authority to return to within BAAL and/or L10. The BCRC will direct its BA to utilize all resources, including firm load shedding, as necessary to relieve an emergency condition. The NWPP Reserve Sharing program is normally the resource used by the BCRC’s Balancing Authority to relieve an emergency condition associated with CPS and DCS compliance.

3.8 The BCRC coordinates with neighbouring RCs, BAs and TOPs, as needed, on the development and implementation of Operating Plans, Procedures, and Processes to mitigate potential or actual SOL and IROL exceedances. The BCRC coordinates pending generation and transmission maintenance outages with other RCs, as necessary, in both the real-time and next-day reliability analysis timeframes. The BCRC participates in periodic conference calls with neighbouring RCs as necessary.

3.9 The BCRC will assist its BA in arranging for assistance from neighboring RCs or Balancing Authorities via the Energy Emergency Alert (EEA) notification process and will conference parties together as appropriate.

3.10 The BCRC monitors the BC Balancing Authority to identify the sources of large ACE that may be contributing to frequency, time error, or inadvertent interchange and directs corrective actions with its Balancing Authority.

3.11 The TOPs within the BCRC Reliability Area must inform the BCRC of all changes in status of Remedial Action Schemes (RAS) including any degradation or potential failure to operate as expected by the TOP. The BCRC factors these RAS changes into its reliability analyses.

5. The BCRC issues alerts, as appropriate, to its BA and TOPs when it foresees a

transmission problem (such as an SOL or IROL exceedance, loss of reactive reserves,

etc.) within its Reliability Area that requires notification. The BCRC issues alerts, as appropriate, to all RCs via the Reliability Coordinator Information System when it foresees a transmission problem (such as an SOL or IROL exceedance, loss of reactive reserves, etc.) within its Reliability Area that requires notification.

6. The BCRC confirms Real-time Assessment results via analyzing results of state estimator/RTCA, and discussions with local TOPs and neighbouring RCs. The BCRC identifies options to mitigate potential or actual SOL or IROL exceedances via examining existing operating plans, system knowledge, and power flow analysis to identify and implement only those actions as necessary as to always act in the best interests of the interconnection.

F. Emergency Operations The BCRC utilizes the BCRC Emergency Operating Procedures, posted on the BCRC extranet site, to return the transmission system to within any applicable IROLs within the required mitigation times. The BCRC Emergency Operating Procedures document the processes and procedures the BCRC follows when directing its BA and TOPs to re-dispatch generation, reconfigure transmission, manage Interchange Transactions, or shed firm load, to return the system to a reliable state. The BCRC coordinates its alert and emergency procedures with other RCs via seam coordination agreements listed in Section H. The BCRC will monitor system frequency and its Balancing Authority’s performance. If the BCRC determines that its BA is contributing to a frequency excursion, the BCRC will direct the BA to use all resources available, including load shedding, to comply with CPS and Contingency Reserve requirements. The BCRC utilizes the BCRC Emergency Operating Procedures when it is experiencing a potential or actual Energy Emergency within its BA, Reserve-Sharing Group, or Load-Serving Entity within its Reliability Coordination Area. The BCRC Emergency Operating Procedures document the processes and procedures the BCRC uses to mitigate the emergency condition, including a request for emergency assistance if required.

G. System Restoration

1. Knowledge of members’ Restoration Plans - The BCRC is knowledgeable of the restoration plans of each of the Transmission Operators in its RC Area and has a written copy of each plan in its possession. The BCRC verifies that the most current plans are on file on an annual basis. Additionally, the BCRC Reliability Coordinators are trained on individual plans during regular training sessions. During system restoration, the BCRC monitors restoration progress and acts to coordinate any needed assistance.

2. BCRC Restoration Plan - The BCRC Restoration Plan includes all BAs and TOPs in its Reliability Coordination Area. The BCRC takes action to restore normal operations once an operating emergency has been mitigated in accordance with its Restoration Plan. This Restoration Plan is drilled at least annually. The BCRC approves, communicates and coordinates the re-synchronizing of major system islands or synchronizing points so as not to cause a burden on member or adjacent Reliability Coordination Areas.

3. Dissemination of Information - The BCRC will disseminate information regarding restoration to neighbouring RCs and BAs/TOPs not immediately involved in restoration by posting pertinent information on the RCIS and/or via direct phone call. The BCRC will also use the NERC Hotline for periodic updates to other RCs if required.

H. Coordination Agreements and Data Sharing Coordination Agreements: The BCRC has executed RC coordination agreements with:

1. Alberta Electric System Operator (AESO) 2. Peak Reliability (Peak)

Data Sharing - The BCRC determines the data requirements to support its reliability coordination tasks and requests such data from entities internal and external to B.C., including adjacent RCs. The BCRC provides for data exchange with entities internal and external to B.C. and adjacent Reliability Coordinators via a secure network. Entities subject to data requests provide data to RCRC via mutually agreeable transfer methods identified in the BCRC’s IRO-010 Data Specification. BCRC provides data to entities outside BCRC via direct links and mutually agreeable transfer methods identified in IRO-010 Data Specifications.

I. Facility The BCRC performs the RC function at the BC Hydro Fraser Valley Office (FVO) located in Langley, British Columbia. FVO has the necessary facilities for the BCRC to perform their responsibilities. The backup facility, in nearby Surrey, BC provides the functional workspace for personnel to perform the Reliability Coordinator function. The FVO and Back Up Control Centre (BUCC) have the necessary voice and data communication links to appropriate entities within the BCRC Area to perform their responsibilities. These communication facilities are staffed and available to act in addressing a real-time emergency condition.

1. Adequate Communication Links – The BCRC has adequate, redundant telecommunications circuits providing both voice and data connectivity with its members. The BCRC maintains satellite phones, Voice over IP phones, cell phones, and redundant, diversely routed telecommunications circuits.

2. Multi-directional Capabilities – The BCRC has multi-directional communications capabilities with its members, and with neighbouring RCs, for both voice and data exchange to meet reliability needs of the Interconnection.

3. Real-time Monitoring - The BCRC RC has detailed real-time monitoring capability of its

Reliability Coordination Area and extensive representation of neighbouring facilities to ensure that potential or actual System Operating Limit or Interconnection Reliability Operating Limit exceedances are identified.

The BCRC monitors Bulk Power System elements (generators, transmission lines, buses, transformers, breakers, etc.) that could result in SOL or IROL exceedances within its Reliability Coordination Area. The BCRC monitors both real and reactive power system flows, and operating reserves, and the status of the Bulk Power System elements that are, or could be, critical to SOLs and IROLs and system restoration requirements within its Reliability Coordination Area.

4. Study and Analysis Tools

4.1 The BCRC has adequate analysis tools, including state estimation, pre-and post-

contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays. The BCRC has detailed monitoring capability of the BCRC Reliability Area and sufficient monitoring capability of the surrounding Reliability Areas to ensure potential reliability issues are identified. The BCRC continuously monitors key transmission facilities in its area in conjunction with the Members monitoring of local facilities and issues.

The BCRC ensures that SOL and IROL monitoring and derivations continue if the main monitoring system is unavailable. The BCRC has backup facilities that shall be exercised if the main monitoring system is unavailable.

The systems used by the BCRC include:

State Estimator and Contingency Analysis

Status and Analog Alarming

Overview Displays of the BCRC Transmission System

One line diagrams for the entire BCRC Transmission System

Transient Stability Analysis (TSA-PM)

Voltage Security Assessment (VSA) The BCRC utilizes these tools, which provide information that is easily understood and interpreted by the BCRC operating personnel. The alarm management is designed to classify alarms in priority for heightened awareness of critical alarms.

4.2 The BCRC controls its RC analysis tools, including approvals for planned

maintenance. The BCRC has procedures in place to mitigate the effects of analysis tool outages.

J. Staffing Staff Adequately Trained and NERC Certified – The BCRC maintains trained RCs on duty at all times. In addition, one or more Reliability Coordinator Engineers are on shift from 8:00 AM to 4:00 PM M-F. The BCRC staffs all operating positions that meet 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 Bulk Power System.

Positions directly responsible for complying with NERC Standards. The BCRC operating personnel all complete training using realistic simulations of system emergencies, in addition to other training required to maintain qualified operation personnel. Comprehensive Understanding - The BCRC operating personnel have an extensive understanding of the BA and TOPs within the BCRC Reliability Coordination Area, including the operating staff, operating practices and procedures, restoration priorities and objectives, outage plans, equipment capabilities, and operational restrictions. The BCRC operating personnel place particular attention on SOLs and IROLs and inter-tie facility limits. The BCRC ensures protocols are in place to allow BCRC operating personnel to have the best available information at all times. The BCRC’s System Operator Training process describes the process by which System Operations personnel are trained to perform their duties, both at entry level and in continuous training status. The BCRC also uses the Operator Training Manual to establish training and documentation requirements for System Operators in the form of position specific curricula, NERC certification Guidelines, On-the-Job qualification Guides, and Technical Qualification Training Checklists. The Technical Qualification Training Checklists contain competencies for the RC System Operator position and other operation positions. An analysis of each operator position was conducted by Subject Matter Experts (SME), Management, and training representatives to develop the checklists. These checklists provide a way to identify, track status, and document completion of required initial training for any new System Operator. Standards of Conduct – The BCRC operates independently of BC Hydro marketing function employees and BC Hydro’s wholly owned market subsidiary, Powerex Corp. The BCRC also operates independently from the BC Hydro BA and TOP. RC Operators do not pass information or data to any marketing function employees that is not made publicly available. The BCRC staff has completed training on the BC Hydro RC Standards of Conduct and on the Transmission Standards of Conduct. Refresher training on both BC Hydro Standards of Conduct is conducted every year. Training records are maintained.

Appendix A – BCRC Governing Documents

1. Reliability Coordinator Standards of Conduct 2. Reliability Coordinator Registered Entities Oversight Group Terms of Reference 3. Reliability Coordinator BA/TOP Operations Working Group Terms of Reference