Agenda Operating Reliability Subcommittee - NERC reliability subcommittee ors 2013... · Operating...

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Agenda Operating Reliability Subcommittee September 9, 2015 | 1:00 p.m. – 5:00 p.m. EDT September 10, 2015 | 8:00 a.m. – 12:00 p.m. EDT ERCOT - Taylor 800 Airport Drive Taylor, Texas Conference: 1-866-740-1260; Access Code: 5247004; Security Code: 097745 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement Agenda 1. Administrative Matters a. Arrangements – Chair Wise b. Announcement of Quorum – Secretary i. Operating Reliability Subcommittee Roster* c. Parliamentary Procedures* – Secretary d. Balancing Authority-to-Reliability Coordinator Mapping* – Secretary e. Future Meetings – Secretary i. September 9 – 10, 2015 – Taylor, TX (hosted by ERCOT) ii. November 10 – 11, 2015 – Charlotte, NC (hosted by Duke Energy) iii. February 9 – 10, 2016 – Tampa, FL (hosted by FRCC) iv. Schedule future meetings 2. Meeting Minutes* – Approve – Chair Wise a. Minutes of May 5 – 6, 2015 Operating Reliability Subcommittee Meeting 3. Reliability Plans* – Chair Wise a. Periodic Review of Reliability Plans i. Guideline for Approving Regional and Reliability Coordinator Reliability Plans* b. New or Revised Reliability Plans for Endorsement

Transcript of Agenda Operating Reliability Subcommittee - NERC reliability subcommittee ors 2013... · Operating...

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Agenda Operating Reliability Subcommittee September 9, 2015 | 1:00 p.m. – 5:00 p.m. EDT September 10, 2015 | 8:00 a.m. – 12:00 p.m. EDT ERCOT - Taylor 800 Airport Drive Taylor, Texas Conference: 1-866-740-1260; Access Code: 5247004; Security Code: 097745 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement Agenda

1. Administrative Matters

a. Arrangements – Chair Wise

b. Announcement of Quorum – Secretary

i. Operating Reliability Subcommittee Roster*

c. Parliamentary Procedures* – Secretary

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

e. Future Meetings – Secretary

i. September 9 – 10, 2015 – Taylor, TX (hosted by ERCOT)

ii. November 10 – 11, 2015 – Charlotte, NC (hosted by Duke Energy)

iii. February 9 – 10, 2016 – Tampa, FL (hosted by FRCC)

iv. Schedule future meetings

2. Meeting Minutes* – Approve – Chair Wise

a. Minutes of May 5 – 6, 2015 Operating Reliability Subcommittee Meeting

3. Reliability Plans* – Chair Wise

a. Periodic Review of Reliability Plans

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

b. New or Revised Reliability Plans for Endorsement

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i. Reliability Plan for the TVA Reliability Coordinator Area

4. Operations Review* – All

a. Operations Review

b. Use of Proxy Flowgates

5. Interconnection Frequency Monitoring*

a. Frequency Monitor Reports and Frequency Excursions

i. Eastern – Chair Wise

ii. ERCOT – Jimmy Hartmann

iii. Western – Michelle Mizumori

iv. Quebec – Maxime Nadeau

6. Time Monitoring Reference Document Task Group Report* – Chair Wise

7. Project 2010-14.2.2 (Phase 2 of Balancing Authority Reliability-based Controls – BAL-004-2 (Time Error Correction)) – Darrel Richardson

8. Geomagnetic Disturbance Reliability Guideline Task Group* – Mike McMullen

9. GridEx III Briefing – Bill Lawrence

10. Fault Induced Delayed Voltage Recovery Advisory – Ryan Quint

11. Short-Term Seasonal Assessment Survey – Pooja Shah

12. Essential Reliability Services Task Force (ERSTF) – Mike McMullen

13. ERSTF Frequency Subgroup Status Report on Inertia and Frequency Response Measures – Julia Matevosjana

14. Proposal to Develop a Reliability Guideline on Data Sharing in Support of the New TOP-003 and IRO-010 Data Specification Standards – Chair Wise

15. Project 2009-02 (Real-time Reliability Monitoring and Analysis Capabilities) – Mark Olson

16. BAAL Reporting Requirements* – Larry Kezele

Objective: On April 16, 2015, FERC approved BAL-001-2 (Real Power Balancing Control Performance). In the order, FERC stated the NERC is to monitor the use of BAAL and take action if certain things occur. NERC is to provide a report to FERC 90 day after the first two years that BAAL is enforceable. The U.S. enforcement date for BAL-001-1 is July 1, 2016. Paragraph 38 of the order states: “We acknowledge NERC’s commitment to take a “first step” to address the Commission’s concerns by providing baseline data, including SOL/IROL exceedances where a balancing authority’s ACE was within its Balancing Authority ACE Limit. However, we agree with those commenters who urge the Commission to require NERC to provide more data than described in the NOPR. Therefore, we direct NERC to make an informational filing 90 days after the end of the two-year period following

Operating Reliability Subcommittee Meeting Agenda – September 9-10, 2015 2

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implementation that includes an analysis of data (all relevant events or a representative sample) on whether experience with the Balancing Authority ACE Limit in the first two years after approval has seen ACE swings and unscheduled power flows or inadvertent interchange that could cause SOL/IROL exceedances. However, if it is evident that during this two-year period the issues discussed above are creating SOL/IROL exceedances NERC should provide that information to the Commission, together with appropriate recommendations for mitigation, as this information becomes available. Further, NERC should also make the underlying data available to Commission staff upon request. Regarding BPA’s concerns about the interplay of Reliability Standards BAL-001-2 and BAL-002-1, the Commission believes those concerns are best addressed if and when NERC files with the Commission proposed changes to Reliability Standard BAL-002-1. However, we expect NERC to retain the data pursuant to the analysis directed above so that it will be available, if needed, to examine the effect of Reliability StandardBAL-002-1 in relation to the Balancing Authority ACE Limit in the future.” Presentation: No Duration: 15 minutes Background Item: FERC Order

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17. EPRI Network Model Management – Pat Brown, EPRI and Jay Britton (Britton Consulting)

18. Status Report of the IDC Association – Mike McMullen

19. Parallel Flow Visualization Reliability Metrics Task Group Report – Don Reichenbach

20. Status Report – Net Actual and Net Scheduled Interchange – Tony Burt and Mike McMullen

Objective: The Operating Committee requested that the Operating Reliability Subcommittee find volunteer reliability coordinators in the Eastern and Western Interconnections to create proposed procedures and technology solutions that would create an error checking matrix of BA interchange data for their respective Interconnections. This project would have BAs share ICCP data with one Reliability Coordinator in their respective Interconnection. The RC would develop an error-checking matrix that could be reviewed if frequency was significantly off-schedule and the underlying cause is not known. The matrix could also be used if a BA's EMS were down as it would provide an alternate ACE calculation for the impacted RC and BA. BAs would share ICCP net interchange actual (by neighbor) and net interchange scheduled (total) data with the designated RC in their respective Interconnection and that the designated RC develop an error checking matrix.

Presentation: No Duration: 15 minutes Background Item: No

21. Draft Reliability Guideline: RCs – BAs – TOPs Communication: Loss of Real-Time Reliability Tools Capability / Loss of Equipment Significantly Affecting ICCP Data – Vice Chair Senkowicz

Objective: At its December 2014 meeting, the Operating Committee approved posting the draft Reliability Guideline: RCs – BAs – TOPs Communication: Loss of Real-Time Reliability Tools Capability / Loss of Equipment Significantly Affecting ICCP Data for a 45-day comment period. The guideline was posted for comment on February 19, 2015 with comments due by April 6, 2015. The Reliability Guideline Task Team (Vice Chair Senkowicz, Mike McMullen, Dave Devereaux, Chris Pilong and Chair Wise) will develop a response to the comments received.

Operating Reliability Subcommittee Meeting Agenda – September 9-10, 2015 3

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Presentation: No Duration: 10 minutes Background Item: Comments Received

22. Energy Emergency Alert Level 3 Reports – Chair Wise

Objective: The ORS reviews recent Energy Emergency Alert Level 3 reports at each of its meetings.

Background: There have been no EEA Level 3 events since the subcommittee’s last meeting.

Presentation: No Duration: 5 minutes Background Item: None

23. NERC Situation Awareness Monitoring of EEA Events – Darrell Moore

a. Standard EOP-002-3.1 — Capacity and Energy Emergencies*

24. Data Exchange Working Group Status Report – Keith Mitchell

a. Discussion – EInet Project

25. Telecommunications Working Group Status Report – Clifton Johnson

*Background materials included.

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116-390 Village Blvd. Princeton, NJ 08540

609.452.8060 | www.nerc.com

1

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.

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Antitrust Compliance Guidelines 2

• 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. 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.

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Agenda Item 1.b.i ORS Meeting

September 9-10, 2015

Operating Reliability Subcommittee

Chairman Joel G Wise

Senior Program Manager Regulatory Compliance

Tennessee Valley Authority 1101 Market St, MR5E Chattanooga, Tennessee 37402

(423) 751-3363 (423) 697-4120 Fx [email protected]

Vice Chairman Eric Senkowicz

Director of Operations Florida Reliability Coordinating Council 3000 Bayport Drive Suite 600 Tampa, Florida 33607

(813) 207-7980 esenkowicz@ frcc.com

Carlie M Brown

Manager, System Operations Southwest Power Pool, Inc. 201 Worthen Dr Little Rock, Arkansas 72223

(501) 614-3569 (501) 482-2013 Fx [email protected]

James D. Castle

Manager of Reliability Compliance and Industry Affairs

New York Independent System Operator 10 Krey Blvd Rensselaer, New York 12114

(518) 356-6244 (518) 356-6118 Fx jcastle@ nyiso.com

David J Devereaux

Manager of Control Room Support

Independent Electricity System Operator 2635 Lakeshore Road West Mississauga, Ontario L5J 4R9

905-855-6439 david.devereaux@ ieso.ca

James E. Hartmann, Jr.

Manager, Systems Operations Electric Reliability Council of Texas, Inc. 2705 West Lake Drive Taylor, Texas 76574

(512) 248-6986 (512) 248-3055 Fx jhartmann@ ercot.com

Anthony P Jankowski

Manager, Electric System Operations

We Energies W237 N1500 Busse Road Waukesha, Wisconsin 53188

(262) 544-7117 (262) 544-7099 Fx tony.jankowski@ we-energies.com

Richard W Kiess

Manager, Reliability Coordination

Peak Reliability 4850 Hohns peak Drive Loveland, Colorado 80538

(970) 776-5567 wkiess@ peakrc.com

Richard McCall

Director, Environmental & Transmission Compliance

North Carolina Electric Membership Corp. 3400 Sumner Boulevard Raleigh, North Carolina 27616

(919) 875-3097 (919) 954-1080 Fx richard.mccall@ ncemcs.com

Michael McMullen

Director, Regional Operations Midcontinent ISO 2985 Ames Crossing Road Eagan, Minnesota 55121

mmcmullen@ misoenergy.org

Michelle Mizumori

Director of Reliability Coordination

Peak Reliability 7600 NE 41st Street Suite 201 Vancouver, Washington 98662

(360) 713-9599 (360) 448-9914 Fx mmizumori@ peakrc.com

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Maxime Nadeau Manager – Systems and SPS

Hydro-Quebec TransEnergie 2 Complexe Desjardins Tour est - Centre Hydro - B1 Montreal, Quebec H5B 1H7

(514) 289-2211 ext. 4044 (514) 289-4556 Fx nadeau.maxime@ hydro.qc.ca

John R. Norden

Director, Operations ISO New England, Inc. One Sullivan Road Holyoke, Massachusetts 01040-2841

(413) 537-7699 (413) 535-4343 Fx jnorden@ iso-ne.com

Christopher Pilong

Manager of Dispatch PJM Interconnection, L.L.C. 955 Jefferson Ave Norristown, Pennsylvania 19403

(610) 666-8917 christopher.pilong@ pjm.com

Donald E. Reichenbach

Manager, System Operations Duke Energy ECO2B 526 South Church Street Charlotte, North Carolina 28202

(704) 382-3146 (704) 382-0380 Fx don.reichenbach@ duke-energy.com

Steven C. Sanders

Operations & Transmission Advisor

Western Area Power Administration - UGPR 2900 4th Avenue North Room 600 P.O. Box 35800 Billings, Montana 59101

(406) 255-2840 (406) 255-2900 Fx [email protected]

J. Clifford Shepard

Project Manager, Generation Southern Company Generation 600 North 18th Street BS-8261 Birmingham, Alabama 35202

(205) 257-6116 (205) 257-5792 Fx jcshepar@ southernco.com

Gregory P. Stone

Director, System Operations Duke Energy Carolina EC02A 526 S. Church Street Charlotte, North Carolina 28202

(704) 382-8021 (704) 382-6938 Fx greg.stone@ duke-energy.com

Christopher A Wakefield

Southern Company Services, Inc. ,

205-257-2626 cwakefie@ southernco.com

NERC Staff Larry J. Kezele

Senior Manager of Operations North American Electric Reliability Corporation 3353 Peachtree Road, N.E. Suite 600, North Tower Atlanta, Georgia 30326

(609) 273-0839 (404) 446-2595 Fx larry.kezele@ nerc.net

Michelle Marx

Executive Assistant North American Electric Reliability Corporation 3353 Peachtree Road, N.E. Suite 600, North Tower Atlanta, Georgia 30326

(404) 446-2560 (404) 446-2595 Fx michelle.marx@ nerc.net

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- 1 -

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 debaterequired, 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 topostpone 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 bringthe 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 ensuresthat 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” constitute a motion and a second.

Agenda Item 1.c ORS Meeting

September 9-10, 2015

kezelel
Typewritten Text
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Agenda Item 1.d ORS Meeting

September 9-10, 2015

1

NERC RELIABILITY COORDINATOR AREAS Effective: August 15, 2015

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

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Agenda Item 1.d ORS Meeting

September 9-10, 2015

2

NERC RELIABILITY COORDINATOR DESKS Effective: August 15, 2015

CURRENT RELIABILITY

COORDINATOR

FUTURE RELIABILITY

COORDINATOR

COMMENT

HQT Same

ONT (IESO) Same

ISONE Same

NBPC Same

NYISO Same

PJM Same

MISO (Carmel, Eagan) Same

SPRC Same

VACARS Same

TVA Same

SOCO Same

FRCC Same

SPP Same

ERCOT Same

PEAK (Loveland, Vancouver) Same

AESO RC2 Same

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

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Agenda Item 1.d ORS Meeting

September 9-10, 2015

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NERC BALANCING AUTHORITY TO RELIABILITY COORDINATOR MAPPING

August 15, 2015 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

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Agenda Item 1.d ORS Meeting

September 9-10, 2015

4

Current Reliability

Coordinator

Balancing Authority

Local Balancing Authority

Future Reliability

Coordinator

Regional Entity

Expected Date For Change

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 OVEC RF EES SERC CLEC SPP LAFA SPP LEPA SPP LAGN SERC SME SERC AESO WECC

AESO3 GWA WECC PEAK WAUW WECC

AVA WECC BCTC WECC

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

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Agenda Item 1.d ORS Meeting

September 9-10, 2015

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Current Reliability

Coordinator

Balancing Authority

Local Balancing Authority

Future Reliability

Coordinator

Regional Entity

Expected Date For Change

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 CFE WECC LDWP WECC SMUD WECC GRIF WECC AZPS WECC EPE WECC DEAA WECC IID WECC PNM WECC NEVP NVE WECC PSCO WECC SRP WECC TEPC WECC WACM WECC WALC WECC HGMA WECC GRID WECC SPC MRO

SPRC ERCO ERCOT ERCOT SWPP SPP SPP SPA SPP 10/1/2015

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Meeting Minutes Operating Reliability Subcommittee May 5–6, 2015

Tennessee Valley Authority 1101 Market Street Chattanooga, Tennessee

The Operating Reliability Subcommittee (ORS) met on May 5–6, 2015 in Chattanooga, Tennessee. The meeting agenda and the attendance list are affixed as Exhibits A and B, respectively.

ORS Chair Joel Wise convened the meeting at 1:00 p.m. EDT. Secretary Larry Kezele announced that a quorum was present, read the Notice of Public Meeting and referred the subcommittee to the NERC Antitrust Compliance Guidelines.

Minutes The subcommittee approved the minutes of the February 10–11, 2015 ORS meeting and the minutes of the March 20, 2015 ORS Executive Committee conference call meeting.

Future Meetings The future subcommittee meetings include:

1. September 9, 2015 (half day) and September 10, 2015 (half day) in Taylor, TX (hosted by ERCOT)

2. November 10, 2015 (half day) and November 11, 2015 (half day) in Charlotte, NC (hosted by DukeEnergy)

3. February 9, 2016 (half day) and February 10, 2016 (half day) in Tampa, FL (hosted by FRCC)

Balancing Authority-to-Reliability Coordinator Mapping The subcommittee reviewed and revised the balancing authority-to-reliability coordinator mapping document.

GridEx III Bill Lawrence, Senior Manager of CIP Awareness, provided an overview of activities being undertaken by CIPC’s Grid Exercise Working Group to prepare for GridEx III (Presentation 1). The primary objectives of GridEx III are to 1) exercise crisis response and recovery, 2) improve communication, 3) identify lessons learned and 4) engage senior leadership. He reviewed the key milestones leading up to the November 18-19, 2015 exercise. The GEWG has subject matter experts from 12 reliability coordinators across the BES to support both exercise planning and conduct. Reliability coordinator to reliability coordinator conference calls will begin toward the end of May 2015 and will continue every third Thursday of the month. A mid-term planning conference is scheduled for June 10-11 and a follow-up final planning conference is scheduled for September 3.

Agenda Item 2.aORS Meeting

September 9-10, 2015

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Reliability Plans Larry Kezele noted that there were no new or revised reliability plans to consider at this meeting. However, he drew the subcommittee’s attention to the table in the agenda packet that reflected the approval dates of all reliability plans. He noted that the TVA, the VACAR-S and the SaskPower reliability plans were due for a three year review in accordance with the Guideline for Approving Regional and Reliability Coordinator Reliability Plans. Operations Review Reliability coordinator (RC) members of the subcommittee discussed operating events within their reliability area that occurred during the spring of 2015 and expectations for system operations for the summer of 2015. Most of the southeastern RCs reported that the spring was very wet and mild. Drought conditions persist in ERCOT and in southern Peak Reliability. PJM provided a brief overview of the April 7, 2015 operational event that resulted in the loss of approximately 2,000 MW of generation and approximately 500 MW of load. The sequence of events and a root cause analysis is currently being conducted. TVA reported that, while it has yet to complete its summer assessment, it will likely see heavier south to north transmission flows. In addition, the ORCA dispatch flow is now at 3,000 MW, which may mean that proxy flowgates will have to be used to control transmission congestion. ISO-NE reported record oil burns, record snowfall and record low temperatures. Use of Proxy Flowgates C. J. Brown, SPP, reviewed the use of proxy flowgates in its reliability area during TLR since the subcommittee’s last meeting (Presentation 2). Addition of AESO to the NERC Reliability Coordinator Hotline The subcommittee expressed its opinion that AESO should execute the NERC Operating Reliability Data Confidentiality Agreement and the Reliability Coordinator Standards of Conduct before it can be allowed to join the NERC RC Hotline. Larry Kezele will address this with NERC legal. Frequency Monitor Reports and Frequency Excursions Nate Schweighart, Eastern Interconnection frequency monitor, reported that there we no significant events to report and no RC hotline calls were initiated due to frequency concerns. There were no reportable frequency events in the ERCOT, Western or Quebec Interconnections. Time Monitoring Reference Document Task Group Report Chair Wise reported that the task group that is reviewing the Time Monitoring Reference Document did not have an opportunity to complete its assignment. This topic will be further reviewed at the subcommittee’s September 2015 meeting. Geomagnetic Disturbance Reference Document Task Group Report Mike McMullen reported that the task group that is reviewing the Geomagnetic Disturbance Reference Document did not have an opportunity to complete its assignment. This topic will be further reviewed at the subcommittee’s September 2015 meeting.

Operating Reliability Subcommittee Minutes – May 5–6, 2015 2

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Associated Electric Cooperative’s Reliability Concerns in the Palmyra, Missouri Area Chair Wise reported that AECI will not be providing an update on this agenda topic at this meeting, however, he will reach out to AECI to request a status report at the September 2015 meeting. Operations Perspective for Seasonal Assessments Pooja Shah, Senior Engineer, briefed the subcommittee on NERC’s efforts to develop the summer and winter seasonal assessments and the consideration being given to providing an increased operational perspective within those assessments (Presentation 3). Traditionally the seasonal assessments have focused on the key planning areas of resource adequacy, reserve margins and transmission adequacy. Ms. Shah noted that, while this has been a valuable resource from a planning perspective, the short-term nature of the winter and summer assessments merit an operational perspective. For example, the 2015 summer assessment included an operational analysis pilot. Ms. Shah sought the subcommittee’s input on 1) content/insights from operations, 2) review of the seasonal assessments and 3) timeline for review. She also noted that NERC staff and the Reliability Assessment Subcommittee are considering transitioning the seasonal assessments to short-term (18-month) assessments, which would also incorporate operational aspects of the system and provide additional analytical information. Ms. Shah noted that this would likely be a discussion topic at the June 9-10, 2015 Operating and Planning Committee meetings. Calculation of Market Flow Data Uploaded to the IDC Raja Thappetaobula, MISO, provided an overview of MISO’s market flow calculation methodology (Presentation 4). Market flow is defined as the calculated energy flows on a specified flow gate as a result of dispatch of generating resources serving market load within a market-based operating entity’s market (excluding tagged transactions). Mr. Thappetaobula explained the MISO market flow calculation logic and provided an example. He also reviewed the sources of input data used to calculate market flow and the periodicity of the calculation. Finally he reviewed how market flows are reported to the IDC for coordinated and reciprocal coordinated flowgates and how market flows are used in the IDC transmission loading relief process. Chris Pilong reported that PJM uses essentially the same methodology as MISO and C. J. Brown reported that SPP used points of receipts and points of delivery as opposed to MISO’s and PJM’s use of marginal zones. Outages of e-Tagging Systems Mike Oatts led the subcommittee is a brief discussion of the scope of this project. He raised such questions as:

1. What e-Tags should continue to flow? For example, should only reliability based e-Tags be allowed to continue to flow?

2. How to determine conservative operations?

3. What is the RC’s desires during this outage period?

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If the subcommittee determines that these issues should be addressed in a reliability guideline, the guideline should focus of the responsibilities of the balancing authorities during e-Tagging system outages. The RC should be considered as having a secondary role. Essential Reliability Services Task Force (ERSTF) Mike McMullen, a member of the ERSTF, reported that during its October 2014 meeting the ERSTF identified nine possible measures and recommended to the Operating Committee moving forward with four of those measures. Measures 1 and 3 identify the parameters and data required to measure historical inertia at an Interconnection and balancing authority level, respectively. Measure 2 calculates a rate of change of frequency for an Interconnection and is intended for the planning horizon level, while Measure 6 identifies ramping capability requirements at the balancing authority level. At its March 2015 meeting, the OC endorsed Measure 7 (Reactive Capability on the System). Measure 7 tracks rotating and non-rotating dynamic reactive capability per total megawatt load on the system at a balancing authority level for various areas at critical load levels (e.g., peak, shoulder and light load). All of the measures will be further refined in future revisions to the ERSTF Phase 2 document. Adjourn and Reconvene The subcommittee adjourned at 4:50 p.m. EDT and reconvened the following morning at 8:02 a.m. EDT. Resolution of Appreciation for Alden Briggs By unanimous consent the ORS approved the following resolution of appreciation:

Whereas, Alden Briggs is retiring from the New Brunswick Power (NBP) and departing the NERC Operating Reliability Subcommittee (ORS). Whereas, Alden Briggs has faithfully and effectively represented NBP and the Industry on the ORS and its Working Group for many years. Whereas, Alden Briggs has supported NERC and its mission by participation on multiple NERC committees and working groups. Resolved, That the ORS thanks Alden for his service and wishes him happiness in his retirement and success in future endeavors.

Resolution of Appreciation for Jim Castle By unanimous consent the ORS approved the following resolution of appreciation:

Whereas, Jim Castle is retiring from the New York Independent System Operator (NYISO) and departing the NERC Operating Reliability Subcommittee (ORS). Whereas, Jim Castle has faithfully and effectively represented NYISO and the Industry on the ORS and its Working Group for many years. Whereas, Jim Castle has supported NERC and its mission by participation on multiple NERC committees and working groups. Resolved, That the ORS thanks Jim for his service and wishes him happiness in his retirement and success in future endeavors.

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IDC Association Status Report Mike Oatts reported that the IDC Association Steering Committee met on the morning of May 5, 2015 and he provided an overview of their activities. The IDC Working Group continues to improve the data flow into the IDC’s Generation-to-Load calculation. As a result several fixes have been implemented to correct bugs in the GTL calculation methodology. The IDCWG is getting ready for metrics testing and model validation. The IDCWG is now focusing its attention on Parallel Flow Visualization design and development. The Steering Committee expects to see a completed PFV change order by July 2015 and it is expected to take approximately one-year to implement that change order. Parallel Flow Visualization Reliability Metrics Task Group Report Don Reichenbach provided an overview of several draft Parallel Flow Visualization test metrics (Presentation 5).

1. Data Availability – Measure performance of data supply (e.g., generator outputs, tie-line flows, system loads, etc.) against requirements.

2. Input Data Accuracy – Measure accuracy of reported data (e.g., generator unit output, balancing authority load, etc.) against actual value.

3. Validate Calculation Logic

a. Flowgate Flows – Measure and track actual flowgate flows against calculated flowgate flows in 15-minute increments.

b. Test three seams agreement methodologies to ensure consistent results.

c. Test against a study power flow case with identical system setup.

4. Pseudo Ties – Test different pseudo tie modelling methodologies to ensure consistent results.

5. Alarming – Confirm alarming for loss of data input, etc.

Following his presentation, the subcommittee discussed the questions shown on the slide at right. The ORS suggested that Mr. Reichenbach coordinate further work on metrics development with the IDCWG. Status Report – Net Actual and Net Scheduled Interchange Mike McMullen reported that MISO volunteered to develop an error-checking matrix to compare actual net interchange (NIa) and scheduled net interchange (NIs) for all BAs in the Eastern Interconnection. The

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project remains under development. Michelle Mizumori reported that Peak Reliability volunteered to develop a similar matrix for the Western Interconnection and is now addressing data validation issues. Draft Reliability Guideline: Reliability Coordinator – BA/TO/TOP Communication: Real-Time Reliability Tools Degradation Vice Chair Senkowicz reported that the draft Reliability Guideline: Reliability Coordinator – BA/TO/TOP Communication: Real-Time Reliability Tools Degradation was posted for a 45-day comment period on February 19, 2015. Comments were due by April 6, 2015. He also provided a high level overview of the comments received. Energy Emergency Alert Level 3 Reports Larry Kezele reported that there have not been any Energy Emergency Alert Level 3 Events since the subcommittee’s last meeting. Data Exchange Working Group (DEWG) A representative of the DEWG was not available to provide a status report of working group activities, however, Chair Wise reported that at the March 2015 Operating Committee meeting it was decided that the DEWG should continue reporting to the ORS through 2015. Telecommunications Working Group (TWG) A representative of the TWG was not available to provide a status report of working group activities. Agenda Topics for the September 2015 ORS Meeting The subcommittee suggested that the following topics be included on the agenda for its September 2015 meeting:

1. EPRI Common Information Model

2. Closing Out System Event Reports Next Meeting The next meeting of the Operating Reliability Subcommittee will be on September 9-10, 2015 in Taylor, Texas. Adjourn There being no further business before the Operating Reliability Subcommittee, Chair Wise adjourned the meeting on Wednesday, May 6, 2015 at 10:06 a.m. EDT.

Larry Kezele Larry Kezele Secretary

Operating Reliability Subcommittee Minutes – May 5–6, 2015 6

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Agenda Item 3 ORS Meeting

September 9-10, 2015

Reliability Plans

ORS Action Required None Background At its March 2007 meeting, the Operating Committee approved the Guideline for Approving Regional and Reliability Coordinator Reliability Plans. The subcommittee will follow these guidelines when reviewing and approving new or revised regional or reliability coordinator reliability plans. Guideline for Approving Regional and Reliability Coordinator Reliability Plans (Agenda Item 3.a.i) Periodic Review of Reliability Plans

Information and Discussion Paragraph 9 of the Guideline for Approving Regional and Reliability Coordinator Reliability Plans states:

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

The following table reflects the approval date of each regional reliability plan or reliability coordinator reliability plan and the approving subcommittee or committee.

Entity Approval Date Entity Approval Date

SaskPower RCP ORS September 10 Peak Reliability RCP

OC December 13

SPP RCP OC March 15 MISO RTO RCP ORS EC March 15 Southeastern RCP ORS May 13 TVA RCP ORS May 12

SERC RRP ORS May 14 PJM RTO RCP ORS EC March 13 ERCOT RCP ORS February 14 NPCC RRP ORS September 13

FRCC RCP ORS November 13 VACAR RRP ORS May 12

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Agenda Item 3 ORS Meeting

September 9-10, 2015

New or Revised Reliability Plans for Endorsement Review and Endorse – Reliability Plan for the TVA Reliability Coordinator Area Nate Schweighart will provide an overview of the revised Reliability Plan for the TVA Reliability Coordinator Area, which will become effective on October 1, 2015 (Agenda Item 3.b.i.). The proposed revisions to the reliability plan are shown on Page 2 in the Revision Log.

Proposed Subcommittee Motion The Operating Reliability Subcommittee endorses the revised Reliability Plan for the TVA Reliability Coordinator Area, which will become effective on October 1, 2015.

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- 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 ORS Meeting

September 9-10, 2015

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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.

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Guideline for Approving Regional and Reliability Coordinator Reliability Plans

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. The Regional Reliability Organization (RRO) shall review and approve its Regional Reliability Plan before it is submitted to NERC for review and approval. The Reliability Coordinator shall submit its Reliability Plan to all Regional Reliability Organizations within which it operates for their respective review and approval before such plan is submitted to NERC for review and approval.

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

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

4. ORS Endorsement of RRP or RCP. Following its review of the RRP or RCP (and the reliability readiness evaluation), the ORS will decide whether to endorse the RRP or RCP for 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 or the Reliability Coordinator.

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

6. Approval of Minor Revisions to a RRP or RCP. The Operating Committee delegates the 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 Reliability Plans and Reliability Coordinator Reliability Plans on its Web site.

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

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Guideline for Approving Regional and Reliability Coordinator Reliability Plans

Approved by Operating Committee March 22, 2007 - 4 -

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

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Guideline for Approving Regional and Reliability Coordinator Reliability Plans

Approved by Operating Committee March 22, 2007 - 5 -

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.

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Agenda Item 3.b.iORS Meeting

September 9-10, 2015

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TOPS-RC Standard

Programs and Processes

Reliability Plan for the TVA Reliability Coordinator Area

TOPS-RC-SPP-30.230 Rev. 0000 Page 2 of 36

Revision Log

Revision or Change Number

Effective Date

Affected Page

Numbers Description of Revision/Change 0000 10-01-2015 All

.

Page 4 .

Page 5,6 .

All

Page 7

Page 17 .

Page 22

Page 23

Page 24

All .

All

TOPS-RC-SPP-30.230 superseded TRO-RC-SPP-30.230.

Update purpose to align with SERC Regional Reliability Plan

Updated Roles and Responsibilities and incorporated GOES verbiage

Reliability Standards cross references added.

Note box added in section 3.2.2.

Updated Emergency Operations section 3.2.5, bullet K.

Added Reference Section

SMT added to Appendix A

Updated Agreements in Appendix B

Source Notes section updated and standard references added to document.

Moved language to different sections for better understanding

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Table of Contents

1.0 PURPOSE ............................................................................................................................... 4

2.0 SCOPE .................................................................................................................................... 4

3.0 PROCESS ............................................................................................................................... 5 3.1 Roles and Responsibilities ....................................................................................................... 5

3.1.1 Transmission Operations & Power Supply (TOPS) Vice President ............................ 5

3.1.2 Manager, Reliability Operations ................................................................................ 5

3.1.3 TVA Reliability Coordinator ....................................................................................... 5

3.1.4 Reliability Operations (RO) ........................................................................................ 6

3.1.5 Reliability Analysis (RA) ............................................................................................ 6

3.1.6 TVA RC Member Companies .................................................................................... 6

3.2 Program Elements ................................................................................................................... 7

3.2.1 Delegation of Tasks .................................................................................................. 7

3.2.2 Common Tasks for Next-Day and Current-Day Operations ....................................... 7

3.2.3 Next-Day Operations [SERC Regional Reliability Plan] ............................................. 8

3.2.4 Current-Day Operations [SERC Regional Reliability Plan] ........................................ 9

3.2.5 Emergency Operations ........................................................................................... 14

3.2.6 System Restoration ................................................................................................. 16

3.2.7 Coordination Agreements and Data Sharing ........................................................... 17

3.2.8 Facility ..................................................................................................................... 18

3.2.9 Staffing .................................................................................................................... 19

4.0 RECORDS ............................................................................................................................. 21 4.1 QA Records ........................................................................................................................... 21

4.2 Non-QA Records .................................................................................................................... 21

5.0 DEFINITIONS ........................................................................................................................ 21

6.0 REFERENCES ...................................................................................................................... 21

Appendix A: TVA RC Member Balancing Authorities and Transmission Operators ............................................................................................................ 23

Appendix B: Reliability Coordination Agreements ................................................................ 24

Appendix C: Adjacent Reliability Coordination Agreements ................................................ 25

Source Notes: Source Notes ...................................................................................................... 26

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1.0 PURPOSE

The overall objective of the Reliability Plan for the Tennessee Valley Authority Reliability Coordinator (TVA RC) area is to ensure and maintain the operational reliability of the TVA Reliability Coordinator wide-area and the Eastern Interconnection [SERC Regional Reliability Plan]. The North American Electric Reliability Corporation (NERC) reliability standard IRO-001 requires Southeastern Reliability Corporation (SERC) region Reliability Coordinators (RC) to establish and provide the reliability assessment and emergency operations coordination for the Balancing Authorities (BA) and Transmission Operators (TOp) within the regions and across the regional boundaries. SERC has established the SERC Regional Reliability Plan. The TVA RC and this document, Reliability Plan for the TVA Reliability Coordinator area, complies with the SERC Regional Reliability Plan [IRO-001-1.1 R2].

2.0 SCOPE

This document represents the Reliability Plan for the TVA Reliability Coordinator area. Upon approval of the NERC Operating Committee, this plan will supersede the previous plan.

The Tennessee Valley Authority serves as the Reliability Coordinator for the TVA Balancing Authority and Transmission Operator. TVA has also entered into Reliability Coordination Agreements (Agreements) with other Balancing Authorities and Transmission Operators (herein referred to as “Members”) to perform the NERC-required Reliability Coordinator function for them. The term “Member” includes TVA Balancing Authority and Transmission Operator functions. The Members operate as Balancing Authorities and/or Transmission Operators in the SERC region. The respective region recognizes TVA as the Reliability Coordinator for the Members. The TVA RC area consists of the Member’s transmission and generation facilities within the Balancing Authorities’ metered boundaries for the Members listed in Appendix A.

TVA RC is responsible for the TVA RC Area bulk transmission reliability and power supply reliability. Bulk transmission reliability functions include reliability analysis, transmission loading relief procedures, re-dispatch of generation and ordering curtailment of transactions and/or load and market flow. Power supply reliability entails monitoring BA performance and directing the BAs and TOps to take actions, including load shed and increasing/decreasing generation in situations where an imbalance between generation and load places the system in jeopardy.

TVA RC Reliability Plan is written taking into account NERC Standards in effect at the effective date of the Plan. Understanding that NERC Standards are subject to change during the term of this Plan, the TVA RC will comply with all applicable NERC Standards, whether expressly addressed in this Plan or not.

Review Cadence: This procedure will be reviewed every 3 years with the review documented in the revision Log.

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3.0 PROCESS

3.1 Roles and Responsibilities

Various groups within TVA comprise and support the TVA Reliability Coordinator function in its responsibility of ensuring and maintaining the operational reliability of the TVA Reliability Coordinator (RC) wide-area and the Eastern Interconnection.

3.1.1 Transmission Operations & Power Supply (TOPS) Vice President

The Transmission Operations & Power Supply Vice President has overall responsibility and governance for all aspects of implementation, as well as, executive approval of this procedure.

3.1.2 Manager, Reliability Operations

The Manager, Reliability Operations, is responsible and has the oversight for the review and technical information contained in this procedure.

3.1.3 TVA Reliability Coordinator

A. TVA RC complies with a regional reliability plan approved by the NERC Operating Committee [IRO-001-1.1 R2]

B. TVA RC will continually assess transmission reliability and coordinate emergency operations around the operating entities within the region and across the regional boundaries [IRO-001-1.1 R1]

C. TVA RC maintains the real-time operating reliability of the TVA RC Area and, in coordination with its neighboring RCs, the wide-area view. The wide-area view includes situational awareness of its neighboring RC Areas. Its scope includes both transmission and balancing operations, and the TVA RC has authority to direct other functional entities to take certain actions to ensure that its RC Area operates reliably [NERC Reliability Functional Model - Version 5].

D. TVA RC has clear decision-making authority to act and to direct actions to be taken by Balancing Authorities, Transmission Operators, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing Selling Entities within its Reliability Coordinator area to preserve the integrity and reliability of the Bulk Electric System. These actions shall be taken without delay, but no longer than 30 minutes [IRO-001-1.1 R3]. TVA RC responsibilities and authority are clearly defined in the executed Reliability Coordination Agreements in Appendix B and the Operating Personnel Responsibility and Authority to Meet NERC Compliance (Authority Letter).

E. TVA RC has clear, comprehensive coordination agreements with adjacent Reliability Coordinators to ensure that System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violation mitigation, requiring actions in adjacent Reliability Coordinator areas, are coordinated [IRO-001-1.1 R7]. Appendix C lists the status of adjacent Reliability Coordination agreements.

F. TVA RC will act in the interests of reliability for the overall RC Area and the Interconnection before the interests of any other entity [IRO-001-1.1 R9].

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3.1.4 Reliability Operations (RO)

A. Reliability Operations is ultimately responsible for executing the RC function at TVA.

B. Responsible for the real-time 24 by 7 RC operations of the TVA RC area.

3.1.5 Reliability Analysis (RA)

A. Reliability Analysis provides engineering support for the RC function and supports the real-time Reliability Coordination Operators in their responsibility to fulfill the function of RC.

B. Responsible for operational planning of the RC Area.

C. Responsible for providing the next-day analysis and assisting in developing the plan for next-day operations.

3.1.6 TVA RC Member Companies

A. TVA RC Area is composed of the Members listed in Appendix A.

B. Each Member of TVA Reliability Coordinator area shall comply with Reliability Coordinator directives unless such actions would violate safety, equipment, or regulatory or statutory requirements. Under these circumstances, the Members shall immediately inform the Reliability Coordinator of the inability to perform the directive so that the Reliability Coordinator may implement alternate remedial actions [IRO-001-1.1 R8].

C. Each Member of TVA Reliability Coordinator area will comply with the directives of the TVA RC based on the next day assessments in the same manner in which it would comply during real time operating events [IRO-004-2 R1].

D. Each Transmission Operator, Balancing Authority, Generator Operator, Generation Owner, Interchange Authority, Load-Serving Entity, Reliability Coordinator, and Transmission Owner with which the TVA RC has a reliability relationship provides the TVA RC with the operating data that the TVA RC requires to perform operational reliability assessments and to coordinate reliable operations within the TVA Reliability Coordinator area [IRO-010-1a R3].

E. Each Member of TVA Reliability Coordinator area provides information required for system studies, such as critical facility status, load, generation, operating reserve projections, and known Interchange Transactions.

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3.2 Program Elements

3.2.1 Delegation of Tasks

A. Reliability Coordinators that delegate tasks to other entities shall have formal operating agreements with each entity to which tasks are delegated. Reliability Coordinator shall verify that all delegated tasks are understood, communicated, and addressed within its Reliability Coordinator area. All responsibilities for complying with NERC and regional standards applicable to Reliability Coordinators shall remain with the Reliability Coordinator [IRO-001-1.1 R4].

B. TVA RC has not delegated any reliability coordinator tasks to any entity outside of TVA [IRO-001-1.1 R5],[SERC Regional Reliability Plan].

3.2.2 Common Tasks for Next-Day and Current-Day Operations

A. TVA RC monitors all Bulk Electric System facilities within its own Reliability Coordinator area and adjacent Reliability Coordinator areas, as necessary, to determine any potential System Operating Limit and Interconnection Reliability Operating Limit violations within its Reliability Coordinator area Regardless of prior planned or unplanned events [IRO-003-2 R1]. TVA RC assesses contingency situations as described in sections below for Current-Day and Next-Day operations.

B. TVA RC contacts neighboring Reliability Coordinator areas when TVA RC is aware of an operational concern, such as declining voltages, excessive reactive flows, or an IROL violation, in a neighboring RC Area. TVA and neighboring Reliability Coordinators coordinate any actions, including emergency assistance required to mitigate the operational concern [IRO-014-1 R1].

C. TVA RC performs analysis and monitoring (as described in the appropriate sections below) of all critical facilities whose failure, degradation, or disconnection could result in any SOL or IROL violation. TVA RC ensures that Balancing Authorities and Transmission Operators within its RC Area always operate under known and studied conditions and do not burden others. TVA RC knows the status of all facilities that may be required to assist area restoration objectives [IRO-003-2 R2]. TVA RC directs action to reposition the power system following contingency events within approved timelines.

NOTE

Reliability Coordinator will utilize 3-way communication when issuing a Directive.

D. TVA RC issues directives in a clear, concise, and definitive manner, ensures the recipient of the directive repeats the information back correctly, and acknowledges the response as correct or repeats the original statement to resolve any misunderstandings [COM-002-2 R2]. RC shall communicate the expected timing associated with the directive, i.e. when the directive is expected to be implemented, the duration of the action, etc.

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E. TVA RC has a documented specification for data and information to build and maintain

models to support Real-time monitoring, Operational Planning Analyses, and Real-time Assessments of the TVA RC Area to prevent instability, uncontrolled separation, and cascading outages [IRO-010-1a R1]. TVA RC has distributed its data specification to entities that have Facilities monitored by TVA RC and entities that provide Facility status to TVA RC [IRO-010-1a R2]. TVA RC data and information specifications are outlined in the Standard Programs and Processes (SPP) document, TVA Reliability Coordinator Data and Information Specifications.

F. TVA RC, via the ISN or equivalent system, exchanges with other Reliability Coordinators operating data that are necessary to allow the Reliability Coordinators to perform operational reliability assessments and coordinate reliable operations. TVA RC does share with other Reliability Coordinators the types of data listed in Attachment 1-TOP-005 “Electric System Reliability Data,” unless otherwise agreed to [TOP-005-2a R1].

3.2.3 Next-Day Operations [SERC Regional Reliability Plan]

A. TVA RC conducts next-day reliability analyses for its RC Area to ensure that the Bulk Electric System can be operated reliably in anticipated normal and contingency event conditions. TVA RC conducts pre and post contingency analysis studies to identify potential interface and other SOL and IROL violations, including thermal monitoring of overloaded transmission lines and transformers, voltage and stability limits, etc. [IRO-004-2].

B. TVA RC will verify adequate operating reserves, area reserves and reactive reserves for the RC Area [SERC Regional Reliability Plan].

C. TVA RC pays particular attention to parallel flows to ensure that the TVA Reliability Coordinator area does not place an unacceptable or undue burden on adjacent Reliability Coordinator areas.

D. TVA RC, in conjunction with other Members within its Reliability Coordinator area, develops required action plans, including reconfiguration of the transmission system re-dispatching of generation reduction or curtailment of Interchange Transactions, or reducing load to return transmission loading to within acceptable SOLs or IROLs [IRO-006-5].

E. TVA RC provides available data such as Bulk Electric System (BES) facility outages, load forecast, and operating reserve projections of the TVA RC Area to the NERC SDX.

F. TVA RC shares the results of its system studies, when conditions warrant or upon request, with other Reliability Coordinators and with Balancing Authorities and Transmission Operators within the TVA Reliability Coordinator area. The TVA RC makes study results available no later than 1500 Central Prevailing Time (CPT), unless circumstances warrant otherwise.

G. When conditions warrant, the TVA RC initiates conference calls or other appropriate communications to address the results of its reliability analyses.

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H. If the results of these studies indicate potential SOL or IROL violations, the TVA RC will

make available the results to member companies and impacted neighboring RC areas and notify those entities as appropriate through communication such as phone calls, conference calls, emails, or Reliability Coordinator Information System (RCIS) as appropriate.

I. TVA RC will determine if operating guides should be developed based on the analysis and will coordinate with Reliability Analysis and the affected RC, TOp and/or BA [SERC Regional Reliability Plan].

J. TVA RC will direct Members in the TVA Reliability Coordinator area to take any necessary action the TVA RC deems appropriate to address the potential SOL or IROL violation. TVA RC will also resolve any scheduling of potential reliability conflicts [TOP-003-1 R4].

3.2.4 Current-Day Operations [SERC Regional Reliability Plan]

A. TVA RC monitors applicable transmission line status real and reactive power flows, voltage, load-tap-changer settings, and status of rotating and static reactive resources [TOP-006-2 R2].

B. TVA RC monitors its Reliability Coordinator area parameters, including, but not limited to the following [IRO-005-3.1a R1]:

1. Current status of BES elements and system loading

2. Current pre-contingency element conditions (voltage, thermal, or stability), including any applicable mitigation plans to alleviate SOL or IROL violations, including the plan’s viability and scope

3. Current post-contingency element conditions (voltage, thermal, or stability), including any applicable mitigation plans to alleviate SOL or IROL violations, including the plan’s viability and scope

4. System real and reactive reserves (actual versus required)

5. Capacity and energy adequacy conditions

6. Current ACE for all Balancing Authorities

7. Current local or Transmission Loading Relief procedures in effect

8. Planned generation dispatches

9. Planned transmission or generation outages

10. Contingency events

C. TVA RC has knowledge of current and planned critical facility status through monitoring of key facilities across the TVA RC Area via real-time and near real-time data sent to the TVA RC by the Members. Planned facility status is communicated via teleconferences and System Data Exchange (SDX) [IRO-003-2 R2].

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D. TVA has an ALSTOM real-time state estimator and security analysis package

(Advanced Network Applications). ALSTOM model has approximately 9,000 detailed modeled stations and buses. Node/breaker detail is provided for the TVA RC area and some external areas. Real-time contingency analysis cycles every two minutes.

E. TVA RC has implemented the PowerWorld Retriever Real-Time Monitoring System. This flow based visualization tool is designed to help system operators and reliability personnel monitor and display the current state of the system. Real time telemetry and State Estimator estimated data are input into the tool. TVA RC System Operators are able to monitor the health of TVA’s RC Area transmission system (and neighboring areas) with a glance using the PowerWorld visual interface, with such functions as voltage contouring. This visualization tool allows the operator to supplement power system studies and create an easy-to-read and easy to understand displays for the wide area view.

F. TVA RC utilizes power flow software to determine line outage distribution factors and applies these factors to critical flow gates. The RC System Operator then monitors these critical facilities and their contingent elements in real time.

G. TVA RC does provide appropriate technical information concerning protective relays to their operating personnel [TOP-006-2 R3].

H. TVA RC does have information, including weather forecasts and past load patterns, available to predict the system’s near-term load pattern.

I. TVA RC does use monitoring equipment to bring to the attention of operating personnel important deviations in operating conditions and to indicate, if appropriate, the need for corrective action. TVA RC’s tools have visual and/or audible alarms to alert the operating personal to conditions that need attention [TOP-006-2 R5].

J. TVA RC is aware of all Interchange Transactions that wheel through, source, or sink in the TVA Reliability Coordinator area, and that Interchange Transaction information is available to all Reliability Coordinators in the Eastern Interconnection via the NERC Interchange Distribution Calculator (IDC) [IRO-006-EAST].

K. As portions of the transmission system approach or exceed SOLs or IROLs, the TVA RC works with Members in the TVA Reliability Coordination area to evaluate and assess any additional Interchange Schedules that would violate those limits. If a potential or actual IROL violation cannot be avoided through proactive intervention, the TVA RC will initiate control actions or emergency procedures to relieve the violation without delay, and no longer than 30 minutes. TVA RC ensures that all resources, including load shedding, are available to address a potential or actual IROL violation [TOP-001-0 R1],[SERC Regional Reliability Plan].

L. TVA RC will identify the cause of any potential or actual SOL or IROL violations. TVA RC will initiate the control action or emergency procedure to relieve the potential or actual IROL violation without delay, and no longer than 30 minutes. The TVA RC will utilize all resources, including load shedding, to address an IROL violation and ensure the system is returned within the IROL [IRO-009-1 R1],[SERC Regional Reliability Plan].

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M. TVA RC monitors its Balancing Authorities’ parameters to ensure that the required

amount of operating reserves is provided and available as required to meet the Control Performance Standard and Disturbance Control Standard requirements. If necessary, TVA RC will direct the Balancing Authorities in its Reliability Coordinator area to arrange for assistance from neighboring Balancing Authorities. TVA RC issues Energy Emergency Alerts as needed and at the request of its Members [IRO-005-3.1a R2].

N. AECI participates in the SPP Reserve Sharing Pool. LG&E/KU and TVA participate in the TEE Reserve Sharing Group. EEI maintains its own reserve requirements.

O. TVA RC ensures its Members are aware of Geo-Magnetic Disturbance (GMD) forecast information and assists as needed in the development of any required response plans [IRO-005-3.1a R3]. The roles and responsibilities associated with GMD of the TVA Reliability Coordinator and Member companies is detailed in the RC Geomagnetic Disturbance Operating Plan Technical Procedure.

P. TVA RC participates in NERC hotline discussions, assists in the assessment of reliability of the overall interconnected system, and coordinates actions in anticipated or actual emergency situations. TVA RC will disseminate such information within its Reliability Coordinator area, as required [IRO-005-3.1a R4].

Q. TVA RC monitors system frequency and its Balancing Authorities’ performance and directs any necessary rebalancing to return to CPS and DCS compliance. The Members will utilize all resources, including firm load shedding, as directed by the TVA RC to relieve an emergent condition [IRO-005-3.1a R5].

R. TVA currently serves as NERC’s Eastern Interconnection Frequency Monitor and initiates NERC Hotline calls when frequency exceeds specified limits. The roles and responsibilities associated with serving as the Eastern Interconnection Frequency Monitor is located in the SPP TVA Reliability Coordinator Responsibility as Eastern Interconnection Frequency Monitor.

S. Each of the other Balancing Authorities within the Reliability Coordinator area provides a frequency data value which is monitored via TVA’s EMS.

T. Frequency used in the TVA Balancing Authority’s ACE calculation is from one of two sources in two geographic locations within the TVA Balancing Authority. The two primary feeds are true-time frequency devices, monitored in the Chattanooga area from the Electric Power Board (EPB), one at the Regional Operations Center (ROC) and the other at the System Operations Center (SOC). The feeds will automatically failover, to the other, if one fails. Frequency indication from several substations across the TVA Balancing Authority area is shown in TVA’s EMS.

U. All Balancing Authorities’ frequency values are displayed via the RCIS. The CERTS Resource Adequacy Monitoring System provides visualization of Balancing Authorities ACE.

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3.1.3 TVA Reliability Coordinator (continued)

V. TVA RC coordinates with other Reliability Coordinators and its Members as needed to

develop and implement action plans to mitigate potential or actual SOL, IROL, CPS, or DCS violations. TVA RC coordinates pending generation and transmission maintenance outages with other Reliability Coordinators and Transmission Operators, Balancing Authorities, and Generator Operators as needed in both the real time and next-day reliability analysis timeframes [IRO-005-3.1a R6].

W. As necessary, the TVA RC assists the Balancing Authorities in its Reliability Coordinator area in arranging for assistance from neighboring Reliability Coordinator areas or Balancing Authorities [IRO-005-3.1a R7].

X. TVA RC monitors ACE for each Balancing Authority within the TVA RC Area and identifies sources of large Area Control Errors that may be contributing to Frequency Error, Time Error, or Inadvertent Interchange and discusses corrective actions with appropriate Balancing Authorities. If a Frequency Error, Time Error, or Inadvertent problem occurs outside of the TVA Reliability Coordinator area, the TVA RC will initiate a NERC hotline call to discuss the Frequency Error, Time Error, or Inadvertent Interchange with other Reliability Coordinators. The TVA RC directs its Balancing Authorities to comply with CPS and DCS [IRO-005-3.1a R8].

Y. Whenever a 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 violation) is armed, the TVA RC will be aware of the impact of the operation of that Special Protection System on inter-area flows. The Member will immediately inform the TVA RC of the status of the Special Protection System including any degradation or potential failure to operate as expected [IRO-005-3.1a R9].

NOTE

There are not any Special Protection Systems (SPS) currently identified in the TVA RC Area.

Z. TVA RC ensures that Members operate to prevent the likelihood that a disturbance, action, or non-action in its Reliability Coordinator area will result in a SOL or IROL violation in another area of the Interconnection. In instances where there is a difference in derived limits, the TVA RC and Members shall always operate the Bulk Electric System to the most limiting parameter [IRO-005-3.1a R10].

AA. TVA RC makes known to its Members within its Reliability Coordinator area the SOLs or IROLs within its wide-area view.

BB. TVA RC foreseeing a transmission problem (such as an SOL or IROL violation, loss of reactive reserves, etc.) within its Reliability Coordinator area will issue an alert to all impacted Members in its Reliability Coordinator area, and all impacted Reliability Coordinators within the Interconnection via the Reliability Coordinator Information System (RCIS) without delay. The receiving Reliability Coordinator will disseminate this information to its impacted Members. TVA RC will notify all impacted Members and Reliability Coordinators when the transmission problem has been mitigated [IRO-005-3.1a R12].

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CC. TVA RC confirms reliability assessment results and determines the effects within the

TVA Reliability Area and adjacent Reliability Coordinator areas. TVA RC will discuss options to mitigate potential or actual SOL or IROL violations and take actions as necessary to always act in the best interests of the Interconnection.

DD. When an IROL or SOL is exceeded, the TVA RC will evaluate the local and wide-area impacts, both real-time and post-contingency, and determine if the actions being taken are appropriate and sufficient to return the system to within IROL in 30 minutes. If the actions being taken are not appropriate or sufficient, the TVA RC will direct the Members to return the system to within IROL or SOL limits [IRO-009-1 R4],[SERC Regional Reliability Plan].

EE. TVA RC experiencing a potential or actual SOL or IROL violation within its Reliability Coordinator area will, at its discretion, select from either a “local” (Regional, Interregional, or sub regional) transmission loading relief procedure and/or Interconnection-wide procedure. The Eastern Interconnection Transmission Loading Relief (TLR) procedure is available for use by the TVA RC via the IDC.

FF. TVA RC notifies its members of transmission problems by telephone and a daily operational conference call (not on weekends or holidays) to discuss reliability issues. TVA RC notifies all RCs via telephone RCIS, or NERC Hotline as appropriate and the TVA RC participates in daily conference calls with adjacent RCs [IRO-015-1 R2].

GG. TVA RC will evaluate actions taken to address an IROL or SOL violation and, if the actions taken are not appropriate or sufficient, direct actions required to return the system to within limits [TOP-007-0 R4].

HH. TVA RC will use local transmission loading relief or congestion management procedures, provided the Transmission Operator experiencing the potential or actual SOL or IROL violation is a party to those procedures. TVA RC may implement a local transmission loading relief or congestion management procedure simultaneously with an Interconnection-wide procedure.

II. However, the TVA RC will follow the curtailments as directed by the Interconnection-wide procedure. If TVA RC desired to use a local procedure as a substitute for curtailments as directed by the Interconnection-wide procedure, then it would have such use approved by the NERC Operating Committee.

JJ. When implemented, the TVA RC will comply with the provisions of the Interconnection-wide procedure including, for example, action by Reliability Coordinators in other Interconnections to curtail an Interchange Transaction that crosses an Interconnection boundary [IRO-006-5 R1].

KK. During the implementation of relief procedures, and up to the point that emergency action is necessary, the TVA RC and Balancing Authorities in the TVA Reliability Area will comply with Interchange Scheduling Standards INT-001 through INT-004.

LL. TVA RC has the authority to request that the Interconnection Time Monitor terminate a Time Error Correction in progress, or a scheduled Time Error Correction that has not begun, for reliability considerations [BAL-004-0 R4].

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3.2.2 Common Tasks for Next-Day and Current-Day Operations (continued)

MM. TVA RC communicates start and end times for time error corrections to the Balancing

Authorities within its RC Area by telephone.

NOTES

1. Only a Reliability Coordinator is eligible to act as Interconnection Time Monitor.

2. A single Reliability Coordinator in each Interconnection is designated by the NERC Operating Committee to serve as Interconnection Time Monitor.

3. TVA RC is not currently the designated Interconnection Time Monitor [BAL-004-0 R1].

3.2.5 Emergency Operations

A. TVA RC and Balancing Authorities and Transmission Operators in the TVA Reliability Coordination area will promptly analyze Bulk Electric System disturbances on its system or facilities.

B. TVA RC will take appropriate actions in accordance with established policies, procedures, authority, and expectations to relieve transmission loading. The document, Transmission Reliability Order of Curtailment outlines the process used by TVA RC regarding actions to be taken to relieve transmission loading issues.

C. TVA RC, Balancing Authorities and/or Transmission Operators in the TVA Reliability Coordination area experiencing a reportable incident shall provide a preliminary written report to the applicable region and NERC as outlined in the standard, EOP-004-2 Event Reporting.

1. TVA RC and/or the affected Balancing Authorities and Transmission Operators in the TVA Reliability Coordination area will submit within 24 hours of the disturbance or unusual occurrence either a copy of the report submitted to DOE, or if no DOE report is required, a copy of the NERC Interconnection Reliability Operating Limit and Preliminary Disturbance Report form. Events that are not identified until sometime after they occur shall be reported within 24 hours of being recognized [EOP-004-2 R2].

2. Applicable reporting forms are provided in NERC Standards Attachments 1-EOP-004 and 2-EOP-004 [EOP-004-2 R1].

3. Under certain adverse conditions, e.g., severe weather, it may not be possible to assess the damage caused by a disturbance and issue a written Interconnection Reliability Operating Limit and Preliminary Disturbance Report within 24 hours. In such cases, TVA RC, Balancing Authority, and/or Transmission Operator will promptly notify applicable regions and NERC, and verbally provide as much information as is available at that time. TVA RC and the affected Balancing Authority and Transmission Operator will provide timely, periodic verbal updates until adequate information is available to issue a written Preliminary Disturbance Report.

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3.2.3 Next-Day Operations [SERC Regional Reliability Plan] (continued)

4. TVA RC is responsible for recognizing incidents that require DOE and NERC

reporting as detailed in EOP-004 and SPP TOPS-SPP-30.050 Operational Desk Responsibilities, Communications and notifications to PSS/ODS who is responsible for making emergency notification to delegated executives in alignment with the Agency Emergency Response Plan duties and NERC/DOE Reporting

D. TVA RC has procedures for the recognition of and for making their operating personnel aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection [CIP-001-1a R1]. TVA RC also has procedures for the communication of information concerning sabotage events to appropriate parties in the Interconnection. TVA RC provides its operating personnel with sabotage response guidelines, including personnel to contact, for reporting disturbances due to sabotage events [TRANS-SPP-14.007]. TVA RC has established communications contacts with local Federal Bureau of Investigation (FBI) officials and develops reporting procedures as appropriate to their circumstances.

E. TVA RC has the responsibility and clear decision-making authority to take whatever actions are needed to ensure the reliability of its respective area and shall exercise specific authority to alleviate capacity and energy emergencies [EOP-002-3.1 R1].

F. TVA RC will direct its Members to implement their capacity and energy emergency plan, when required and as appropriate, to reduce risks to the interconnected system.

G. TVA RC will communicate its Members’ current and future system conditions to neighboring areas if it experiences an operating capacity or energy emergency.

H. TVA RC experiencing a potential or actual Energy Emergency in its Reliability Area will initiate an Energy Emergency Alert as detailed in NERC Standard Attachment 1-EOP-002 “Energy Emergency Alert Levels”. TVA RC will act to mitigate the emergency condition, including a request for emergency assistance if required [EOP-002-3.1 R8].

I. When a Member expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from Non-designated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources) as permitted in its transmission tariff [EOP-002-3.1 R9]:

1. TVA RC will submit the report to NERC for posting on the NERC website, noting the expected total MW that may have its transmission service priority changed.

2. TVA RC will use EEA 1 to forecast the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7.

3. TVA RC will use EEA 2 to announce the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7.

J. TVA RC has a plan to continue reliability operations in the event its control center becomes inoperable [EOP-008-1]. The contingency plan meets the following requirements:

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3.2.4 Current-Day Operations [SERC Regional Reliability Plan] (continued)

1. The contingency plan shall not rely on data or voice communication from the

primary control facility to be viable.

2. The plan shall include procedures and responsibilities for providing basic tie line control and procedures and for maintaining the status of all inter-area schedules, such that there is an hourly accounting of all schedules.

3. The contingency plan must address monitoring and control of critical transmission facilities, generation control, voltage control, time and frequency control, control of critical substation devices, and logging of significant power system events. The plan shall list the critical facilities.

4. The plan shall include procedures and responsibilities for maintaining basic voice communication capabilities with other areas.

5. The plan shall include procedures and responsibilities for conducting periodic tests, at least annually, to ensure viability of the plan.

6. The plan shall include procedures and responsibilities for providing annual training to ensure that operating personnel are able to implement the contingency plans.

7. The plan shall be reviewed and updated every 3 years.

8. Interim provisions must be included if it is expected to take more than one hour to implement the contingency plan for loss of primary control facility.

K. TVA operates a primary System Operations Center (SOC) for the TVA Reliability Coordinator (RC), TVA Transmission Provider/Interchange Authority (TISO), TVA Balancing Authority (BA) and TVA Transmission Operations (TOp) functions. TVA has a redundant, fully functional Backup Operations Center (BOC) located at the Regional Operations Center (ROC) on the Chickamauga Reservation. The backup facility has full monitoring, control, logging, and alarming capabilities. During a transition from the primary control center to the backup control center, the RC will relocate to the BOC in a tiered approach, while NERC Certified System Operators continue to monitor the system. The SOC and BOC have backup power supplies and fully redundant communication systems independent of each other. Any transfer to the BOC will be transparent to the external entities as a phone script rolls the RC phone contact from the SOC to the BOC. Once the RC has assumed control at the BOC, notification will be posted on RCIS informing external entities of the RC location to the backup facility. NERC requirements provide for a transition time of 2 hours or less when transferring from the primary control center to the backup control center [EOP-008-1 R1].

3.2.6 System Restoration

A. TVA RC has a Reliability Coordinator area restoration plan that provides coordination between individual Member restoration plans and that ensures reliability is maintained during system restoration events [EOP-006-2 R1].

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3.2.4 Current-Day Operations [SERC Regional Reliability Plan] (continued)

B. TVA RC shall review restoration plan of each Member in its Reliability Coordinator area

in accordance with NERC standard EOP-005. TVA RC shall determine whether the Transmission Operator’s restoration plan is coordinated and compatible with the TVA RC’s restoration plan and other Transmission Operators’ restoration plans within its Reliability Coordinator area. TVA RC shall approve or disapprove, with stated reasons, the Transmission Operator’s submitted restoration plan within 30 calendar days following the receipt of the restoration plan from the Transmission Operator [EOP-006-2 R5].

C. TVA RC will serve as the primary contact for disseminating information regarding restoration to neighboring Reliability Coordinators and Members not immediately involved in restoration [EOP-006-2 R7].

D. TVA RC will monitor restoration progress and coordinate any needed assistance.

E. TVA RC will approve, communicate, and coordinate the re-synchronizing of major system islands or synchronizing points so as not to cause a burden on Members or adjacent Reliability Coordinator areas [EOP-006-2 R8].

F. TVA RC will take actions to restore normal operations once an operating emergency has been mitigated in accordance with its restoration plan.

G. TVA RC assists the Members in re-establishing normal system configuration and coordinate communications as required.

H. TVA RC have a copy of its latest restoration plan and copies of the latest approved restoration plan of each Transmission Operator in its Reliability Coordinators Area within its primary and backup control rooms so that it is available to all of its System Operators prior to the implementation date [EOP-006-2 R6].

3.2.7 Coordination Agreements and Data Sharing

A. TVA RC has Coordination Agreements in place with all of its neighboring Reliability Coordinators. Those are Southwest Power Pool (SPP), Southeastern RC (SOCO), VACAR South, PJM and MISO (refer to Appendix C).

B. TVA RC determines the data requirements to support its reliability coordination tasks and requests such data from Members or adjacent Reliability Coordinators.

C. TVA RC provides for data exchange with Members and Reliability Coordinators, Transmission Operators, and Balancing Authorities via a secure network [IRO-010-1a R2].

D. TVA RC Area Members and other RCs provide data as requested to support reliability coordination.

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3.2.4 Current-Day Operations [SERC Regional Reliability Plan] (continued)

3.2.8 Facility

A. TVA performs the Reliability Coordinator function at the System Operations Center (SOC) located in Chattanooga, Tennessee. The SOC has the necessary voice and data communications links to appropriate entities within its Reliability Coordination Area for the TVA RC to perform their responsibilities. These communications facilities are staffed and available to act in addressing a real-time emergency condition [IRO-002-2 R1].

B. TVA RC has multi-directional communications capabilities with its Members, and with neighboring Reliability Coordinators, for both voice and data exchange to meet reliability needs of the Interconnection.

C. TVA RC has detailed real-time monitoring capability of its Reliability Coordinator area and sufficient monitoring capability of its surrounding Reliability Coordinator areas to ensure that potential or actual System Operating Limit or Interconnection Reliability Operating Limit violations are identified. TVA RC has monitoring systems that provide information that is easily understood and interpreted by the Reliability Coordinator’s operating personnel. Particular emphasis is given to alarm management and awareness systems, automated data transfers, and synchronized information systems, over a redundant and highly reliable infrastructure [IRO-002-2 R4].

D. TVA RC monitors Bulk Electric System elements (generators, transmission lines, buses, transformers, breakers, etc.) that could result in SOL or IROL violations within its Reliability Coordinator area. TVA’s RC monitors both real and reactive power system flows, operating reserves, and the status of Bulk Electric System elements that are, or could be, critical to SOLs and IROLs and system restoration requirements within its Reliability Coordinator area [IRO-002-2 R5].

E. TVA RC has adequate analysis tools, including state estimation, pre-and post-contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays [IRO-002-2 R6]. TVA RC has detailed monitoring capability of the TVA Reliability Area and sufficient monitoring capability of the surrounding Reliability Areas to ensure potential reliability violations are identified. TVA RC continuously monitors key transmission facilities in its area in conjunction with the Members monitoring of local facilities and issues. TVA RC receives SCADA information at a four second per scan update rate and ISN data that updates at least every thirty seconds.

F. TVA RC ensures that SOL and IROL monitoring and derivations continue if the main monitoring system is unavailable [IRO-002-2 R7]. TVA’s RC has provisions for backup tools that shall be exercised if the main monitoring system is unavailable. Communication facilities at the SOC and the BOC are fully redundant and independent from each other.

G. TVA RC controls its Reliability Coordinator analysis tools, including approvals for planned maintenance. TVA’s RC has procedures in place to mitigate the effects of analysis tool outages [IRO-002-2 R8].

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3.2.4 Current-Day Operations [SERC Regional Reliability Plan] (continued)

H. TVA RC and Members have adequate and reliable telecommunications facilities for the

exchange of Interconnection and operating information [COM-001-1.1 R1]:

1. Internally.

2. Between TVA RC and Members.

3. With other Reliability Coordinators, Transmission Operators, and Balancing Authorities as necessary to maintain reliability.

4. Where applicable, these facilities are redundant and diversely routed.

I. TVA RC manages, alarm, test and/or actively monitor vital telecommunications facilities. Special attention is given to emergency telecommunications facilities and equipment not used for routine communications [COM-001-1.1 R2].

J. TVA RC and Members provide a means to coordinate telecommunications among their respective areas. This coordination includes the ability to investigate and recommend solutions to telecommunications problems within the area and with other areas [COM-001-1.1 R3].

K. TVA RC and Members use English as the language for all communications between and among operating personnel responsible for the real-time generation control and operation of the interconnected Bulk Electric System. Members may use an alternate language for internal operations [COM-001-1.1 R4].

L. TVA RC has written operating instructions and procedures to enable continued operation of the system during the loss of telecommunications facilities [COM-001-1.1 R5].

M. TVA RC, as a NERCNet User Organization, adheres to the requirements in Attachment 1-COM-001-1, “NERCNet Security Policy”, [COM-001-1.1 R6].

3.2.9 Staffing

A. TVA RC staff all operating positions that meet both of the following criteria with personnel that are NERC certified for the applicable functions:

1. Positions that have the primary responsibility, either directly or through communications with others, for the real-time operation of the interconnected Bulk Electric System.

2. Positions directly responsible for complying with NERC standards [PER-001-0.2 R1].

B. The TVA System Operations Center is staffed with adequately trained and NERC-certified RC operators, 24 hours per day, and seven days per week [PER-004-2 R1].

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3.2.4 Current-Day Operations [SERC Regional Reliability Plan] (continued)

C. TVA RC operating personnel, each complete a minimum of thirty-two (32) hours per

year of training and drills using realistic simulations of system emergencies, in addition to other training required to maintain qualified operating personnel [PER-005-1 R3].

D. TVA RC operating personnel have a comprehensive understanding of the Reliability Coordinator area and interactions with neighboring Reliability Coordinator areas.

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

F. TVA RC operating personnel do place particular attention on SOLs and IROLs and inter-tie facility limits. TVA RC ensures protocols are in place to allow Reliability Coordinator operating personnel to have the best available information at all times [PER-004-2 R2].

G. TVA’s TOPS System Operator Training Process (document TOPS-SPP-30.043) describes the process by which System Operations personnel are trained to perform their duties, both at entry level and in continuing training status. The Technical Qualification Training Checklists contain competencies for the RC System Operator position and the Specialist, Analysis and Operations position. 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 [PER-003-1 R1].

H. TVA uses several means to provide initial and continuing training opportunities for System Operators. TVA Technical Training provides much of the corporate and non-technical courses such as Standards of Conduct, Fitness for Duty, Ethics and Employee Conducts and Disciplinary Guidelines. Information Technology (IT) Education provides training on computer based applications such as Word, Excel, Access Database, etc. Technical Training supports the development/procurement of technical training for System Operators such as the L&K Computer Based Training series on Transmission System Operations and the SOS training for NERC certification exam preparation. Continuing training is designed to keep System Operators knowledgeable of NERC Standards, operating policies, tools and equipment, and management expectations. Drills on emergency procedures and simulated exercises are included in continuing training activities. This training also provides sufficient NERC Continuing Education Hours (CEH) in order for the System Operators to maintain their NERC Certification.

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3.2.5 Emergency Operations (continued)

I. Operators in training will work shift with Certified Operators prior to assuming shift

independently. By rotating with different Reliability Coordinators the employee is exposed to different ideas and thought processes of those currently holding shift. Only with the input from skilled RCs who have worked with the trainee, completion of the Technical Qualification Training Checklist, and the successful completion of NERC certification, can the supervisor assess the employee's readiness to operate unsupervised. These Technical Qualification Training Checklists are then retained for documentation.

J. TVA RC is independent of the merchant function. RC does not pass information or data to any wholesale merchant function or retail merchant function (either internal or external) that is not made available simultaneously to all such wholesale merchant functions. An officer of TVA signed the NERC Reliability Coordinators Standards of Conduct on October 13, 2000 and this information is posted at www.nerc.com/~filez/sc-soc/signers.html. TVA’s RC staff has completed training on TVA’s Standards of Conduct. Refresher training on TVA’s Standards of Conduct is required every year. Training records are maintained.

4.0 RECORDS

4.1 QA Records

None

4.2 Non-QA Records

Technical Qualification Training Checklist

5.0 DEFINITIONS

Defined within the document.

6.0 REFERENCES

Operating Personnel Responsibility and Authority to Meet NERC Compliance (Authority Letter)

TRO-RC-SPP-30.248 “TVA Reliability Coordinator Data and Information Specification”

TOPS-RC-SOP-30.249 “RC Geomagnetic Disturbance Operating Plan”

TOPS-RC-SPP-30.203 “TVA Reliability Coordinator Responsibility as Eastern Interconnection Frequency Monitor”

TOPS-SPP-30.050 “Operational Desk Responsibilities, Communications and NERC-DOE Reporting”

TOPS-RC-SPP-30.205 “Transmission Reliability Order of Curtailment”

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3.2.5 Emergency Operations (continued)

SERC Regional Reliability Plan

NERC Reliability Functional Model - Version 5

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Appendix A (Page 1 of 1)

TVA RC Member Balancing Authorities and Transmission Operators

Associated Electric Cooperative, Inc. (AECI): BA and TOp

Electric Energy, Inc. (EEI): BA and TOp

Smoky Mountain Transmission (SMT): TOp

Louisville Gas and Electric Company and Kentucky Utilities Company (LGEE): BA and TOp

Owensboro Municipal Utility (OMU): TOp

Tennessee Valley Authority (TVA): BA and TOp

Alcoa Power Generating, Inc. - Tapoco (APGI): TOp

Memphis Light Gas & Water (MLGW): TOp

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Appendix B (Page 1 of 1)

Reliability Coordination Agreements

“Reliability Coordination Agreement” executed by TVA and EEI (06/28/04)

“Reliability Coordination Umbrella and Related Services Agreement” executed by TVA and AECI (09/30/05)

“Reliability Coordination Agreement” executed by TVA and LGEE/KU (04/07/06)

“Memorandum of Understanding” executed by TVA and MLGW (01/01/11)

“Reliability Coordination Agreement” executed by TVA and SMT (11/15/12)

“Reliability Coordination Agreement” executed by TVA and OMU (11/01/14)

“Reliability Coordination Agreement” executed by TVA and APGI (02/27/15)

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Appendix C (Page 1 of 1)

Adjacent Reliability Coordination Agreements

TVA - PJM: Joint Reliability Coordination Agreement Amount And Between PJM Interconnection, L.L.C., And Tennessee Valley Authority (10/15/14)

TVA - VACAR South: Adjacent Reliability Coordinator Coordination Agreement (06/29/06)

TVA - Southern Company: Adjacent Reliability Coordinator Coordination Agreement (08/28/06)

TVA - SPP: Adjacent Reliability Coordinator Coordination Agreement (06/12/06)

TVA - MISO: Adjacent Reliability Coordinator Coordination Agreement (06/15/11)

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Source Notes (Page 1 of 11)

Requirements Statement Source Document Implementing

Statement

Objective of the Reliability Plan for the TVA RC Area is to ensure and maintain the operational reliability

SERC Regional Reliability Plan Section 1.0, 3.2.3, 3.2.4

The Reliability Coordinator shall comply with a regional reliability plan approved by the NERC Operating Committee.

IRO-001-1.1 R2 Section 1.0, 3.1.3

Each Regional Reliability Organization, subregion, or interregional coordinating group shall establish one or more Reliability Coordinators

IRO-001-1.1 R1 Section 3.1.3

The Reliability Coordinator maintains the Real-time operating reliability of its Reliability Coordinator area and in coordination with its neighboring Reliability Coordinator's wide-area view.

NERC Reliability Functional Model - Version 5

Section 3.1.3

The Reliability Coordinator shall have clear decision-making authority to act and to direct actions to be taken by

IRO-001-1.1 R3 Section 3.1.3

The Reliability Coordinator shall have clear, comprehensive coordination agreements with adjacent Reliability Coordinators to ensure that System Operating Limit or Interconnection Reliability Operating Limit

IRO-001-1.1 R7 Section 3.1.3

Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling Entities shall comply with Reliability Coordinator directives

IRO-001-1.1 R8 Section 3.1.6

The Reliability Coordinator shall act in the interests of reliability for the overall Reliability Coordinator area and the Interconnection before the interests of any other entity.

IRO-001-1.1 R9 Section 3.1.3

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Source Notes (Page 2 of 11)

3.2.9 Staffing (continued)

Each Transmission Operator, Balancing Authority, and Transmission Service Provider shall comply with the directives of its Reliability Coordinator based on the next day assessments in the same manner in which it would comply during real time operating events.

IRO-004-2 R1 Section 3.1.6

Each Balancing Authority, Generator Owner, Generator Operator, Interchange Authority, Load-serving Entity Reliability Coordinator, Transmission Operator, and Transmission Owner shall provide data and information

IRO-010-1a R3 Section 3.1.6

Reliability Coordinators that delegate tasks to other entities shall have formal operating agreements with each entity to which tasks are delegated.

IRO-001-1.1 R4 Section 3.2.1

The Reliability Coordinator shall list within its reliability plan all entities to which the Reliability Coordinator has delegated required tasks.

IRO-001-1.1 R5 Section 3.2.1

Each Reliability Coordinator shall monitor all Bulk Electric System facilities, which may include sub-transmission information, within its Reliability Coordinator area and adjacent Reliability Coordinator areas

IRO-003-2 R1 Section 3.2.2

The Reliability Coordinator shall have Operating Procedures, Processes, or Plans in place for activities that require notification, exchange of information or coordination of actions with one or more other Reliability Coordinators to support Interconnection reliability.

IRO-014-1 R1 Section 3.2.2

Reliability Coordinators shall also know the status of any facilities that may be required to assist area restoration objectives.

IRO-003-2 R2 Section 3.2.2

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Source Notes (Page 3 of 11)

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall issue directives in a clear, concise, and definitive manner;

COM-002-2 R2 Section 3.2.2

The Reliability Coordinator shall have a documented specification for data and information to build and maintain models to support Real-time monitoring

IRO-010-1a R1 Section 3.2.2

The Reliability Coordinator shall distribute its data specification to entities that have Facilities monitored by the Reliability Coordinator and to entities that provide Facility status to the Reliability Coordinator.

IRO-010-1a R2 Section 3.2.2

As a condition of receiving data from the Interregional Security Network (ISN), each ISN data recipient shall sign the NERC Confidentiality Agreement for “Electric System Reliability Data.”

TOP-005-2a R1 Section 3.2.2

Each Reliability Coordinator must conduct next-day reliability analyses for its Reliability Coordinator area to ensure the Bulk Electric System can be operated reliably in anticipated normal and Contingency conditions.

IRO-004-2, Purpose Section 3.2.3

To ensure coordinated action between Interconnections when implementing Interconnection-wide transmission loading relief procedures to prevent or manage potential or actual SOL and IROL exceedances to maintain reliability of the bulk electric system.

IRO-006-5, Purpose Section 3.2.3

Each Reliability Coordinator shall resolve any scheduling of potential reliability conflicts.

TOP-003-1 R4 Section 3.2.3

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Source Notes (Page 4 of 11)

Reliability Coordinator shall have one or more Operating Processes, Procedures, or Plans that identify actions it shall take or actions it shall direct others to take (up to and including load shedding) that can be implemented in time to prevent exceeding those IROLs.

IRO-009-1 R1 Section 3.2.3

Each Reliability Coordinator shall monitor its Reliability Coordinator area parameters, including but not limited to the following

IRO-005-3.1a R1 Section 3.2.4

Each Reliability Coordinator shall know the current status of all critical facilities whose failure, degradation or disconnection could result in an SOL or IROL violation.

IRO-003-2 R2 Section 3.2.4

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall monitor applicable transmission line status Real and reactive power flows, voltage, load-tap-changer settings, and status of rotating and static reactive resources.

TOP-006-2 R2 Section 3.2.4

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall provide appropriate technical information concerning protective relays to their operating personnel.

TOP-006-2 R3 Section 3.2.4

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use monitoring equipment to bring to the attention of operating personnel important deviations in operating conditions and to indicate, if appropriate, the need for corrective action.

TOP-006-2 R5 Section 3.2.4

Each Reliability Coordinator shall monitor its Balancing Authorities’ parameters to ensure that the required amount of operating reserves is provided and available as required to meet the Control Performance Standard and Disturbance Control Standard requirements.

IRO-005-3.1a R2 Section 3.2.4

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Source Notes (Page 5 of 11)

Each Reliability Coordinator shall ensure its Transmission Operators and Balancing Authorities are aware of Geo-Magnetic Disturbance (GMD) forecast information and assist as needed in the development of any required response plans.

IRO-005-3.1a R3 Section 3.2.4

The Reliability Coordinator shall disseminate information within its Reliability Coordinator area, as required.

IRO-005-3.1a R4 Section 3.2.4

Each Reliability Coordinator shall monitor system frequency and its Balancing Authorities’ performance and direct any necessary rebalancing to return to CPS and DCS compliance.

IRO-005-3.1a R5 Section 3.2.4

The Reliability Coordinator shall coordinate with Transmission Operators, Balancing Authorities, and Generator Operators as needed to develop and implement action plans to mitigate potential or actual SOL, CPS, or DCS violations.

IRO-005-3.1a R6 Section 3.2.4

As necessary, the Reliability Coordinator shall assist the Balancing Authorities in its Reliability Coordinator area in arranging for assistance from neighboring Reliability Coordinator areas or Balancing Authorities.

IRO-005-3.1a R7 Section 3.2.4

The Reliability Coordinator shall direct its Balancing Authority to comply with CPS and DCS.

IRO-005-3.1a R8 Section 3.2.4

Whenever a Special Protection System that may have an inter-Balancing Authority, or inter- Transmission Operator impact

IRO-005-3.1a R9 Section 3.2.4

In instances where there is a difference in derived limits, the Transmission Operators, Balancing Authorities, Generator Operators,

IRO-005-3.1a R10 Section 3.2.4

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Source Notes (Page 6 of 11)

Each Reliability Coordinator who foresees a transmission problem (such as an SOL or IROL violation, loss of reactive reserves, etc.) within its Reliability Coordinator area shall issue an alert to

IRO-005-3.1a R12 Section 3.2.4

When actual system conditions show that there is an instance of exceeding an IROL in its Reliability Coordinator area, the Reliability Coordinator shall, without delay, act or direct others to act to mitigate the magnitude and duration of the instance of exceeding that IROL within the IROL’s Tv.

IRO-009-1 R4 Section 3.2.4

When acting or instructing others to act to mitigate the magnitude and duration of the instance of exceeding an IROL within that IROL’s TV, each Reliability Coordinator shall initiate,

IRO-006-EAST-1 R1 Section 3.2.4

To provide an Interconnection-wide transmission loading relief procedure (TLR) for the Eastern Interconnection that can be used to prevent and/or mitigate potential or actual System Operating Limit (SOL) and Interconnection Reliability Operating Limit (IROL) exceedances to maintain reliability of the Bulk Electric System (BES).

IRO-006-EAST-1 Section 3.2.4

The Reliability Coordinator shall participate in agreed upon conference calls and other communication forums with adjacent Reliability Coordinators.

IRO-015-1 R2 Section 3.2.4

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

TOP-007-0 R4 Section 3.2.4

Each Reliability Coordinator and Balancing Authority that receives a request pursuant to an Interconnection-wide transmission loading relief procedure

IRO-006-5 R1 Section 3.2.4

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Source Notes (Page 7 of 11)

Only a Reliability Coordinator shall be eligible to act as Interconnection Time Monitor.

BAL-004-0 R1 Section 3.2.4

Any Reliability Coordinator in an Interconnection shall have the authority to request the Interconnection Time Monitor to terminate a Time Error Correction in progress, or a scheduled Time Error Correction that has not begun, for reliability considerations.

BAL-004-0 R4 Section 3.2.4

Each Balancing Authority and Reliability Coordinator shall have the responsibility and clear decision-making authority to take

EOP-002-3.1 R1 Section 3.2.5

A Reliability Coordinator that has any Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency shall initiate an Energy Emergency Alert as detailed in Attachment 1-EOP-002 “Energy Emergency Alerts.”

EOP-002-3.1 R8 Section 3.2.5

When a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6

EOP-002-3.1 R9 Section 3.2.5

Each Responsible Entity shall have an event reporting Operating Plan in accordance with EOP-004-2 Attachment 1

EOP-004-2 R1 Section 3.2.5

Each Responsible Entity shall report events per their Operating Plan within 24 hours

EOP-004-2 R2 Section 3.2.5

Ensure continued reliable operations of the Bulk Electric System (BES) in the event that a control center becomes inoperable.

EOP-008-1 Purpose Section 3.2.5

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Source Notes (Page 8 of 11)

Each Reliability Coordinator, Balancing Authority, and Transmission Operator shall have a current Operating Plan describing the manner in which it continues to meet its functional obligations with regard to the reliable operations of the BES in the event that its primary control center functionality is lost.

EOP-008-1 R1 Section 3.2.5

Each Reliability Coordinator, Balancing Authority, Transmission Operator, Generator Operator, and Load Serving Entity shall have procedures for the recognition of and for making their operating personnel aware of sabotage events on its facilities and multi-site sabotage affecting larger portions of the Interconnection.

CIP-001-1a R1 Section 3.2.5

Reporting Vandalism, Sabotage or Other Security Events to Appropriate Parties on the Interconnect.

TRANS-SPP-14.007 Section 3.2.7 Section 3.2.5

Each Reliability Coordinator shall have a Reliability Coordinator area restoration plan.

EOP-006-2 R1 Section 3.2.6

The Reliability Coordinator shall coordinate or authorize resynchronizing islanded areas that bridge boundaries between Transmission Operators or Reliability Coordinators.

EOP-006-2 R8 Section 3.2.6

Each Reliability Coordinator shall have a copy of its latest restoration plan and copies of the latest approved restoration plan

EOP-006-2 R6 Section 3.2.6

Each Reliability Coordinator shall review the restoration plans required by EOP-005 of the Transmission Operators within its Reliability Coordinator Area

EOP-006-2 R5 Section 3.2.6

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Source Notes (Page 9 of 11)

Reliability Coordinators to monitor restoration progress, coordinate restoration, and take actions to restore the BES frequency within acceptable operating limits.

EOP-006-2 R7 Section 3.2.6

The Reliability Coordinator shall distribute its data specification to entities that have Facilities monitored by the Reliability Coordinator and to entities that provide Facility status to the Reliability Coordinator.

IRO-010-1a R2 Section 3.2.7

Each Reliability Coordinator shall have adequate communications facilities (voice and data links) to appropriate entities within its Reliability Coordinator area.

IRO-002-2 R1 Section 3.2.8

Each Reliability Coordinator shall have detailed real-time monitoring capability of its Reliability Coordinator area and sufficient monitoring capability of its surrounding

IRO-002-2 R4 Section 3.2.8

Each Reliability Coordinator shall monitor Bulk Electric System elements (generators, transmission lines, buses, transformers, breakers, etc.) that could result in SOL or IROL violations within its Reliability Coordinator area.

IRO-002-2 R5 Section 3.2.8

Each Reliability Coordinator shall have adequate analysis tools such as state estimation, pre-and post-contingency analysis capabilities (thermal, stability, and voltage), and wide-area overview displays.

IRO-002-2 R6 Section 3.2.8

Each Reliability Coordinator shall ensure SOL and IROL monitoring and derivations continue if the main monitoring system is unavailable.

IRO-002-2 R7 Section 3.2.8

Each Reliability Coordinator shall control its Reliability Coordinator analysis tools, including approvals for planned maintenance.

IRO-002-2 R8 Section 3.2.8

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Source Notes

(Page 10 of 11)

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide adequate and reliable telecommunications facilities for the exchange of Interconnection and operating information:

COM-001-1.1 R1 Section 3.2.8

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall manage, alarm, test and/or actively monitor vital telecommunications facilities.

COM-001-1.1 R2 Section 3.2.8

Each Reliability Coordinator, Transmission Operator and Balancing Authority shall provide a means to coordinate telecommunications among their respective areas.

COM-001-1.1 R3 Section 3.2.8

Unless agreed to otherwise, each Reliability Coordinator, Transmission Operator, and Balancing Authority shall use English as the language for all communications

COM-001-1.1 R4 Section 3.2.8

Each Reliability Coordinator, Transmission Operator, and Balancing Authority shall have written operating instructions and procedures to enable continued operation of the system during the loss of telecommunications facilities.

COM-001-1.1 R5 Section 3.2.8

Each NERCNet User Organization shall adhere to the requirements in Attachment 1-COM-001, “NERCNet Security Policy.”

COM-001-1.1 R6 Section 3.2.8

Each Reliability Coordinator shall be staffed with adequately trained and NERC-certified Reliability Coordinator operators, 24 hours per day, seven days per week.

PER-004-2 R1 Section 3.2.9

At least every 12 months each RC shall be provided with at least 32 hours of emergency operations training, which included system restoration using drills, exercises or other training required to maintain qualified personnel.

PER-005-1 R3 Section 3.2.9

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Source Notes

(Page 11 of 11)

Reliability Coordinator operating personnel shall place particular attention on SOLs and IROLs and inter-tie facility limits.

PER-004-2 R2 Section 3.2.9

Each Transmission Operator and Balancing Authority shall provide operating personnel with the responsibility and authority

PER-001-0.2 R1 Section 3.2.9

Each Reliability Coordinator shall staff its Real-time operating positions performing Reliability Coordinator reliability-related tasks with System Operators who have demonstrated minimum competency in the areas listed by obtaining and maintaining a valid NERC Reliability Operator certificate

PER-003-1 R1 Section 3.2.9

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Agenda Item 4 ORS Meeting

September 9-10, 2015

Operations Review

ORS Action Required Discussion Operations Review The subcommittee will conduct a roundtable discussion of system operations since its May 2015 meeting. This provides an opportunity to share “lessons learned.”

Summer 2015 — Report on unusual operating situations that occurred during the summer of 2015. Fall 2015 — Report on unusual operating situations expected for the upcoming fall of 2015.

Use of Proxy Flowgates The subcommittee will have a roundtable discussion related to each reliability coordinator’s use of proxy flowgates since the last meeting.

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Agenda Item 5 ORS Meeting

September 9–10, 2015

Interconnection Frequency Monitoring

ORS Action Required Discussion Frequency Monitor Report Interconnection frequency monitors will review their respective frequency excursion event logs. Secretary’s Note: At its May 2007 meeting, the Reliability Coordinator Working Group (RCWG) modified the criteria for initiating a NERC hotline conference call following a frequency excursion from those excursions 5-minutes or longer in duration to those excursions of 10 minutes or longer in duration. Frequency Excursions Secretary’s Note: At its November 2007 meeting, the working group decided that only those frequency excursions that exceeded 10-minutes in duration would be reviewed. There were no frequency excursions since the last working group meeting that met the above criteria. Criteria for Conducting Frequency Excursion Reviews 1. Reliability coordinators will review the first frequency event, where an Intelligent Alarm is issued,

following each ORS meeting, given that that frequency event was at least 10-minutes in duration. 2. The chair of the ORS will forward the Intelligent Alarm to the ORS and request the reliability

coordinators with balancing authorities, as identified in the Intelligent Alarm that contributed at least 500 MW to the frequency excursion alarm condition to conduct individual reviews of the event.

3. Those individual balancing authority reviews will consist of analyzing ACE graphs, tie-line error graphs, systems conditions, root causes, and actions taken to correct ACE.

4. Those reliability coordinators with balancing authorities contributing at least 500 MW to the frequency excursion alarm condition will present the results of their individual reviews to the ORS at its next meeting.

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116-390 Village Blvd. Princeton, NJ 08540

609.452.8060 | www.nerc.com

Time Monitoring Reference Document

Introduction This procedure outlines responsibilities of reliability coordinators serving as time monitors in the North American interconnections. Changes to this reference document will be at the direction of the NERC Operating Committee (OC) with the participation of the NERC Resources Subcommittee (RS) and the Operating Reliability Subcommittee (ORS).

This document applies to current and future frequency or time related procedural responsibilities assigned to the time monitor in NERC standards or NAESB business practices.

Designation of Time Monitor There will be one time monitor within each interconnection. NERC ORS will nominate a time monitor for each interconnection. The ORS will present the nomination to the NERC OC for acceptance. The NERC OC will forward the nomination to the NERC Board of Trustees for approval.

The term of each time monitor shall be one (1) year. With the exception of the Eastern Interconnection, the time monitor term shall be automatically renewed unless requested otherwise by providing a minimum of six (6) months notice to the NERC ORS. The Eastern Interconnection Time Monitor will rotate on an annual basis as outlined below. Should an existing or future time monitor no longer be willing or able to fulfill its responsibilities, the NERC Operating Committee will direct the NERC ORS to nominate a replacement and communicate the transition plan.

If a time monitor fails to fulfill its responsibilities, the NERC ORS will work with the time monitor to resolve the problem. The NERC ORS will submit a report to the NERC OC either identifying corrective measures taken or provide a recommendation for a new time monitor.

The NERC RS will report to the NERC OC and ORS any frequency or time error issues that may have been caused or aggravated by the time monitor or time error correction (TEC) practices.

Responsibilities of the Time Monitor The time monitor will start and stop time error corrections as outlined in NERC standards and NAESB business practices.

The time monitor will terminate any TEC believed to be negatively impacting reliability. Requests for termination may come from any transmission operator or balancing authority operator to its respective reliability coordinator, who will notify the respective Interconnection’s time monitor.

Agenda Item 6 ORS Meeting

September 9-10, 2015

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Time Monitoring Reference Document Version 2 Approved by NERC OC on December 7–8, 2010

2

The time monitor will provide accumulated time error following each TEC or at least monthly to the balancing authorities within its interconnection. References Links to each time monitor’s local procedures to meet this procedure will be posted at the NERC RS Web site (http://www.nerc.com/filez/rs.html). Interconnection Time Monitors Each interconnection has identified the following reliability coordinator as its time monitor:

1. ERCOT Interconnection – ERCOT reliability coordinator 2. Québec Interconnection – Hydro-Québec TransÉnergie reliability coordinator 3. Eastern Interconnection – The reliability coordinators in the Eastern Interconnection will

rotate the time monitor responsibilities on an annual basis as follows: a. IESO (Ontario) – February 1, 2011 through January 31, 2012 b. NBSO (New Brunswick System Operator) – February 1, 2012 through January

31, 2013 c. VACAR-South – February 1, 2013 through January 31, 2014 d. SPP – February 1, 2014 through January 31, 2015 e. NYISO – February 1, 2015 through January 31, 2016 f. PJM – February 1, 2016 through January 31, 2017 g. FRCC – February 1, 2017 through January 31, 2018 h. ICTE – February 1, 2018 through January 31, 2019 i. ISO-NE – February 1, 2019 through January 31, 2020 j. SaskPower – February 1, 2020 through January 31, 2021 k. Southeastern – February 1, 2021 through January 31, 2022 l. TVA – February 1, 2022 through January 31, 2023 m. Midwest ISO – February 1, 2023 through January 31, 2024

4. WECC Interconnection – WECC reliability coordinator

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Version 2 GMD−1 Approved by Operating Committee: September 14, 2005

Geomagnetic Disturbance Reference Document Version 2

Introduction Geomagnetic Disturbances (GMDs) are capable of causing serious disruptions to electric power systems, especially in the northern United States and Canada. This Reference Document explains how GMD watches, alerts, and warnings are provided to the Reliability Coordinators and other operating entities in the Eastern, ERCOT, TransEnergie, and Western Interconnections.

The National Oceanic and Atmospheric Administrations Space Environmental Center (SEC – http://www.sec.noaa.gov/today.html), located in Boulder, Colorado, provides a solar disturbance forecasting service. Although SEC is unable to predict precisely when solar flares will occur, it is able to determine when the disturbance is just beginning.

The information from SEC is made available to the Midwest ISO (MISO), St. Paul, Minnesota office, which has been designated to receive and disseminate notifications of possible GMDs to Reliability Coordinators, balancing authorities, and transmission operators in the Eastern and ERCOT Interconnections. The information from SEC is also made available to Bonneville Power Administration (BPA), which has been designated to receive notifications of possible GMDs and to disseminate such notifications to Reliability Coordinators and other operating entities within the Western Interconnection. The TransEnergie Interconnection receives notifications of possible GMDs from the Solar Terrestrial Dispatch Center.

Terms The complete Glossary of Solar Terrestrial Terms is located at http://www.sec.noaa.gov/info/glossary.html.

A-Index — A daily index of geomagnetic activity derived as the average of the eight 3-hourly A-indices.

A-Index Watch — An A-Index Watch is issued when the daily Boulder, Colorado A-index is predicted to be greater than 20, 30, 50, or 100, with one day or greater lead-time, in the daily forecasts issued by SEC. A-index watches are issued for valid times corresponding to entire calendar days, based upon the daily analyses and forecasts produced by SEC. They serve as a long lead-time prediction of the expected trend in geomagnetic activity, within the limits of what the 24-hour A-index value can describe.

Ap-Index — An averaged planetary A-Index based on data from a set of specific stations.

Flare — A sudden eruption of energy on the solar disk lasting minutes to hours, from which radiation and particles are emitted.

Geomagnetic Storm — A worldwide disturbance of the earth's magnetic field, distinct from regular diurnal variations.

K-Index — A 3-hourly quasi-logarithmic local index of geomagnetic activity relative to an assumed quiet-day curve for the recording site. Range is from 0 to 9. The K-index measures the deviation of the most disturbed horizontal component.

Agenda Item 8 ORS Meeting

September 9-10, 2015

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Geomagnetic Disturbance Reference Document

Version 2 GMD−2 Approved by Operating Committee: September 14, 2005

K-Index Warning — K-Index Warnings are issued and/or extended for any period with expected values of K equal to or greater than 4. Higher K-Index Warnings supersede lower ones. A more thorough description of K-Index Warnings is provided at http://www.sec.noaa.gov/alerts/description.html#K. K-Index Warnings are issued by SEC under two conditions:

1. Warning of expected onset of geomagnetic activity, and/or,

2. Warning of expected persistence of geomagnetic activity.

K-Index Alert — K-Index Alerts, for values of K-4 through K-9, are issued on a near real-time criteria, based on thresholds of deflection from quiet-day curve values for geomagnetic field components over synoptic, 3-hour periods. A more thorough description of K-Index Alerts is provided at http://www.sec.noaa.gov/alerts/description.html#K.

Explanation of Geomagnetic Disturbance Watches, Warnings and Alerts The following table defines geomagnetic activity in terms of the A and K Indexes. “A” refers to the 24-hour A-Index observed at a mid-latitude observatory such as Fredericksburg, Virginia, not the planetary A-Index (Ap) that is based on data from a set of specific stations. The K-Indices are, likewise, mid-latitude values.

NOTE: Sudden commencements are indicated by beginning times, given to the nearest minute. Gradual commencements are indicated by beginning times, to the nearest hour.

Activity A and K Indexes

Quiet A < 7, usually no K-indices > 2

Unsettled 7 < A < 15, usually no K-indices > 3

Active 15 < A < 30, a few K-indices of 4

Minor geomagnetic storm 30 < A < 50, K-indices mostly 4 and 5

Major geomagnetic storm 50 < A < 100, K-indices mostly 5 and 6

Severe geomagnetic storm A > 100, some K-indices 7 or greater

Minimum Reporting Requirements Each Interconnection shall designate an operating entity (e.g. a Reliability Coordinator) to receive geomagnetic disturbance watches, alerts and warnings. All K-7 or higher GMD warnings and alerts shall be routed by established procedures to operating entities within the applicable Interconnection.

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Geomagnetic Disturbance Reference Document

Version 2 GMD−3 Approved by Operating Committee: September 14, 2005

The Geomagnetic Disturbance Phenomenon Solar flares cause relatively rapid transient fluctuation in the earth’s magnetic field (geomagnetic field). These transient geomagnetic field variations produce an induced earth-surface-potential (ESP). The ESP can be on the order of five to ten volts per mile, and results in geomagnetically induced currents (GIC). These currents cause abnormal disturbances in communication, pipeline, railroad signal, and power systems that are grounded to the earth at points remote from each other. The periodicity of the GIC varies over a very wide cycle range. Micro-pulsations are superimposed on alternations spanning a very wide band of low frequencies. Some GIC have a fundamental period on the order of minutes, appearing as quasi-dc compared to 60 Hz or higher frequency.

Geomagnetic storms can produce spurious, quasi-dc currents in electric power systems. Power system disturbances due to the geomagnetic storms were noted as early as 1940. Other major power system disturbances due to geomagnetic storms occurred in 1957, 1958, 1968, 1970, 1972, 1974, 1979, 1982, 1983, and 1989.

Studies have reaffirmed that geological conditions override the effect of latitude. The magnitude of the induced earth-surface-potential (ESP) per mile is normally greater with increasing latitude, however, in areas, which are located over a highly resistive igneous rock formation, the ESP forces large quasi-dc current flows over the transmission system rather than through the higher resistivity surface rock.

Geomagnetic storms cause large fluctuations in the earth’s magnetic field and differences in potential between points of ground. It is known that during these storms, geomagnetically induced currents (GIC) are produced in the electric power systems. These GICs enter and exit through grounded neutrals of wye-connected transformers. The GICs can be many times larger than the Root Mean Square (RMS) value of the AC exciting current, resulting in severe half-cycle saturation and increased transformer VAR demands. Problems, which have been detected during solar magnetic disturbances, are:

Unusual noises and heating in transformers

Real and reactive power swings

Elevated neutral amperes in transformers

Frequency excursions

Tripping of capacitor banks by neutral ground current

Harmonic currents

Hunting of automatic LTC transformers

Voltage fluctuations

Communication system problems

Oscillograph operations

Operation or non-operation of protective relays

Negative sequence relays alarmed

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Standard EOP-002-3.1 — Capacity and Energy Emergencies

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A. Introduction 1. Title: Capacity and Energy Emergencies

2. Number: EOP-002-3.1

3. Purpose: To ensure Reliability Coordinators and Balancing Authorities are prepared forcapacity and energy emergencies.

4. Applicability

4.1. Balancing Authorities.

4.2. Reliability Coordinators.

4.3. Load-Serving Entities.

5. (Proposed) Effective Date: First day of the first calendar quarter six months followingapplicable regulatory approval; or, in those jurisdictions where no regulatory approval isrequired, the first day of the first calendar quarter six months following Board of Trusteesadoption.

B. Requirements R1. Each Balancing Authority and Reliability Coordinator shall have the responsibility and clear

decision-making authority to take whatever actions are needed to ensure the reliability of its respective area and shall exercise specific authority to alleviate capacity and energy emergencies.

R2. Each Balancing Authority shall, when required and as appropriate, take one or more actions as described in its capacity and energy emergency plan to reduce risks to the interconnected system.

R3. A Balancing Authority that is experiencing an operating capacity or energy emergency shall communicate its current and future system conditions to its Reliability Coordinator and neighboring Balancing Authorities.

R4. A Balancing Authority anticipating an operating capacity or energy emergency shall perform all actions necessary including bringing on all available generation, postponing equipment maintenance, scheduling interchange purchases in advance, and being prepared to reduce firm load.

R5. A deficient Balancing Authority shall only use the assistance provided by the Interconnection’s frequency bias for the time needed to implement corrective actions. The Balancing Authority shall not unilaterally adjust generation in an attempt to return Interconnection frequency to normal beyond that supplied through frequency bias action and Interchange Schedule changes. Such unilateral adjustment may overload transmission facilities.

R6. If the Balancing Authority cannot comply with the Control Performance and Disturbance Control Standards, then it shall immediately implement remedies to do so. These remedies include, but are not limited to:

R6.1. Loading all available generating capacity.

R6.2. Deploying all available operating reserve.

R6.3. Interrupting interruptible load and exports.

R6.4. Requesting emergency assistance from other Balancing Authorities.

R6.5. Declaring an Energy Emergency through its Reliability Coordinator; and

Agenda Item 23.aORS Agenda

September 9-10, 2015

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R6.6. Reducing load, through procedures such as public appeals, voltage reductions, curtailing interruptible loads and firm loads.

R7. Once the Balancing Authority has exhausted the steps listed in Requirement 6, or if these steps cannot be completed in sufficient time to resolve the emergency condition, the Balancing Authority shall:

R7.1. Manually shed firm load without delay to return its ACE to zero; and

R7.2. Request the Reliability Coordinator to declare an Energy Emergency Alert in accordance with Attachment 1-EOP-002 “Energy Emergency Alerts.”

R8. A Reliability Coordinator that has any Balancing Authority within its Reliability Coordinator area experiencing a potential or actual Energy Emergency shall initiate an Energy Emergency Alert as detailed in Attachment 1-EOP-002 “Energy Emergency Alerts.” The Reliability Coordinator shall act to mitigate the emergency condition, including a request for emergency assistance if required.

R9. When a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from Non-designated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources) as permitted in its transmission tariff:

R9.1. The deficient Load-Serving Entity shall request its Reliability Coordinator to initiate an Energy Emergency Alert in accordance with Attachment 1-EOP-002 “Energy Emergency Alerts.”

R9.2. The Reliability Coordinator shall submit the report to NERC for posting on the NERC Website, noting the expected total MW that may have its transmission service priority changed.

R9.3. The Reliability Coordinator shall use EEA 1 to forecast the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7.

R9.4. The Reliability Coordinator shall use EEA 2 to announce the change of the priority of transmission service of an Interchange Transaction on the system from Priority 6 to Priority 7.

C. Measures M1. Each Reliability Coordinator and Balancing Authority shall have and provide upon request

evidence that could include but is not limited to, job descriptions, signed agreements, authority letter signed by an appropriate officer of the company, or other equivalent evidence that will be used to confirm that it meets Requirement 1.

M2. If a Reliability Coordinator or Balancing Authority implements one or more actions described in its Capacity and Energy Emergency plan, that entity shall have and provide upon request evidence that could include but is not limited to, operator logs, voice recordings or transcripts of voice recordings, electronic communications, computer printouts or other equivalent evidence that will be used to determine if the actions it took to relieve emergency conditions were in conformance with its Capacity and Energy Emergency Plan. (Requirement 2)

M3. If a Balancing Authority experiences an operating Capacity or Energy Emergency it shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if it met Requirement 3.

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M4. The Balancing Authority shall have and provide upon request evidence (such as operator logs, work orders, E-Tags, or other evidence) that it took the actions described in R4 in response to anticipating a capacity or energy emergency.

M5. The Balancing Authority shall have and provide upon request evidence (such as operator logs, dispatch instructions, or other evidence) that it only used the assistance provided by the Interconnection frequency bias for the time needed to implement corrective actions and did not attempt to return Interconnection frequency to normal through unilateral adjustment of generation beyond that supplied through the frequency bias action and Interchange Schedule changes. (Requirement 5)

M6. The Balancing Authority shall have and provide upon request evidence (such as operator logs, dispatch instructions, or other evidence) that it took actions such as those listed in R6 to comply with CPS and DCS.

M7. The Balancing Authority shall have and provide upon request evidence (such as operator logs, voice recordings, or other evidence) that it took the actions listed in R7 when unable to resolve an emergency condition.

M8. If a Reliability Coordinator has any Balancing Authority within its Reliability Coordinator Area that has notified the Reliability Coordinator of a potential or actual Energy Emergency, the Reliability Coordinator involved in the event shall have and provide upon request evidence that could include, but is not limited to operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence to determine if it initiated an Energy Emergency Alert as specified in Requirement 8 and as detailed in Attachment 1-EOP-002 “Energy Emergency Alerts.”

M9. If a Transmission Service Provider expects to elevate the transmission service priority of an Interchange Transaction from Priority 6 (Network Integration Transmission Service from Non-designated Resources) to Priority 7 (Network Integration Transmission Service from designated Network Resources), the Reliability Coordinator involved in the event shall have and provide upon request evidence that could include, but is not limited to, NERC reports, EEA reports, operator logs, voice recordings or transcripts of voice recordings, electronic communications, or other equivalent evidence that will be used to determine if that Reliability Coordinator met Requirements 9.2, 9.3 and 9.4.

D. Compliance 1. Compliance Monitoring Process

1.1. Compliance Enforcement Authority

Regional Entity

1.2. Compliance Monitoring Period and Reset Timeframe

Not Applicable.

1.3. Compliance Monitoring and Enforcement Process

Compliance Audits

Self-Certifications

Spot Checking

Compliance Violation Investigations

Self-Reporting

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Standard EOP-002-3.1 — Capacity and Energy Emergencies

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Complaints

1.4. Data Retention

For Measure 1, each Reliability Coordinator and Balancing Authority shall keep The current in-force documents.

For Measure 2, 8 and 9 the Reliability Coordinator shall keep 90 days of historical data.

For Measure 3, 4, 5, 6, and 7 the Balancing Authority shall keep 90 days of historical data.

If an entity is found non-compliant the entity shall keep information related to the noncompliance until found compliant or for two years plus the current year, whichever is longer.

Evidence used as part of a triggered investigation shall be retained by the entity being investigated for one year from the date that the investigation is closed, as determined by the Compliance Monitor.

The Compliance Monitor shall keep the last periodic audit report and all requested and submitted subsequent compliance records.

1.5. Additional Compliance Information

None.

E. Regional Differences None identified.

Version History Version Date Action Change Tracking

0 April 1, 2005 Effective Date New

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

1 September 19, 2006 Changes R7. to refer to “Requirement 6” instead of “Requirement 7”

Errata

2 November 1, 2006 Adopted by Board of Trustees Revised

2 November 1, 2006 Corrected numbering in Section A.4. “Applicability.”

Errata

2 October 1, 2007 Added to Section 1 inadvertently omitted “4.3. Load-Serving Entities

Errata

2.1 October 29, 2008 BOT adopted errata changes; updated version number to “2.1”

Errata

2.1 May 13, 2009 FERC Approved Revised

3 June 4, 2010 Modified to address Order No. 693 Directives contained in paragraphs 582.

Revised.

3 August 5, 2010 Adopted by NERC Board of Trustees New

3.1 March 8, 2012 Errata adopted by Standards Committee; (Updated title of Attachment 1 and changed

Errata

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Standard EOP-002-3.1 — Capacity and Energy Emergencies

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references to Attachment 1 throughout Standard from “Attachment 1-EOP-002-0 Energy Emergency Alert Levels” to “Attachment 1-EOP-002 Energy Emergency Alerts”. Removed parenthetical in Requirement R9 referencing a retired Attachment in IRO-006)

3.1 September 13, 2012 FERC Approved Errata

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Standard EOP-002-3.1 — Capacity and Energy Emergencies

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Attachment 1-EOP-002 Energy Emergency Alerts

Introduction This Attachment provides the procedures by which a Load Serving Entity can obtain capacity and energy when it has exhausted all other options and can no longer provide its customers’ expected energy requirements. NERC defines this situation as an “Energy Emergency.” NERC assumes that a capacity deficiency will manifest itself as an energy emergency.

The Energy Emergency Alert Procedure is initiated by the Load Serving Entity’s Reliability Coordinator, who declares various Energy Emergency Alert levels as defined in Section B, “Energy Emergency Alert Levels,” to provide assistance to the Load Serving Entity.

The Load Serving Entity who requests this assistance is referred to as an “Energy Deficient Entity.”

NERC recognizes that Transmission Providers are subject to obligations under FERC-approved tariffs and other agreements, and nothing in these procedures should be interpreted as changing those obligations.

A. General Requirements

1. Initiation by Reliability Coordinator. An Energy Emergency Alert may be initiated only by a Reliability Coordinator at 1) the Reliability Coordinator’s own request, or 2) upon the request of a Balancing Authority, or 3) upon the request of a Load Serving Entity.

1.1. Situations for initiating alert. An Energy Emergency Alert may be initiated for the following reasons:

• When the Load Serving Entity is, or expects to be, unable to provide its customers’ energy requirements, and has been unsuccessful in locating other systems with available resources from which to purchase, or

• The Load Serving Entity cannot schedule the resources due to, for example, Available Transfer Capability (ATC) limitations or transmission loading relief limitations.

2. Notification. A Reliability Coordinator who declares an Energy Emergency Alert shall notify all Balancing Authorities and Transmission Providers in its Reliability Area. The Reliability Coordinator shall also notify all other Reliability Coordinators of the situation via the Reliability Coordinator Information System (RCIS). Additionally, conference calls between Reliability Coordinators shall be held as necessary to communicate system conditions. The Reliability Coordinator shall also notify the other Reliability Coordinators when the alert has ended.

B. Energy Emergency Alert Levels

Introduction To ensure that all Reliability Coordinators clearly understand potential and actual energy emergencies in the Interconnection, NERC has established three levels of Energy Emergency Alerts. The Reliability Coordinators will use these terms when explaining energy emergencies to each other. An Energy Emergency Alert is an emergency procedure, not a daily operating practice, and is not intended as an alternative to compliance with NERC reliability standards or power supply contracts.

The Reliability Coordinator may declare whatever alert level is necessary, and need not proceed through the alerts sequentially.

1. Alert 1 — All available resources in use.

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Standard EOP-002-3.1 — Capacity and Energy Emergencies

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Circumstances:

• Balancing Authority, Reserve Sharing Group, or Load Serving Entity foresees or is experiencing conditions where all available resources are committed to meet firm load, firm transactions, and reserve commitments, and is concerned about sustaining its required Operating Reserves, and

• Non-firm wholesale energy sales (other than those that are recallable to meet reserve requirements) have been curtailed.

2. Alert 2 — Load management procedures in effect.

Circumstances:

• Balancing Authority, Reserve Sharing Group, or Load Serving Entity is no longer able to provide its customers’ expected energy requirements, and is designated an Energy Deficient Entity.

• Energy Deficient Entity foresees or has implemented procedures up to, but excluding, interruption of firm load commitments. When time permits, these procedures may include, but are not limited to:

o Public appeals to reduce demand.

o Voltage reduction.

o Interruption of non-firm end use loads in accordance with applicable contracts1

o Demand-side management.

.

o Utility load conservation measures.

During Alert 2, Reliability Coordinators, Balancing Authorities, and Energy Deficient Entities have the following responsibilities:

2.1 Notifying other Balancing Authorities and market participants. The Energy Deficient Entity shall communicate its needs to other Balancing Authorities and market participants. Upon request from the Energy Deficient Entity, the respective Reliability Coordinator shall post the declaration of the alert level along with the name of the Energy Deficient Entity and, if applicable, its Balancing Authority on the NERC website.

2.2 Declaration period. The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 2 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators, Balancing Authority, and Transmission Providers.

2.3 Sharing information on resource availability. A Balancing Authority and market participants with available resources shall immediately contact the Energy Deficient Entity. This should include the possibility of selling non-firm (recallable) energy out of available Operating Reserves. The Energy Deficient Entity shall notify the Reliability Coordinators of the results.

2.4 Evaluating and mitigating transmission limitations. The Reliability Coordinators shall review all System Operating Limits (SOLs) and Interconnection Reliability Operating Limits (IROLs) and transmission loading relief procedures in effect that may limit the Energy Deficient Entity’s scheduling capabilities. Where appropriate, the Reliability Coordinators shall inform

1 For emergency, not economic, reasons.

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the Transmission Providers under their purview of the pending Energy Emergency and request that they increase their ATC by actions such as restoring transmission elements that are out of service, reconfiguring their transmission system, adjusting phase angle regulator tap positions, implementing emergency operating procedures, and reviewing generation redispatch options.

2.4.1 Notification of ATC adjustments. Resulting increases in ATCs shall be simultaneously communicated to the Energy Deficient Entity and the market via posting on the appropriate OASIS websites by the Transmission Providers.

2.4.2 Availability of generation redispatch options. Available generation redispatch options shall be immediately communicated to the Energy Deficient Entity by its Reliability Coordinator.

2.4.3 Evaluating impact of current transmission loading relief events. The Reliability Coordinators shall evaluate the impact of any current transmission loading relief events on the ability to supply emergency assistance to the Energy Deficient Entity. This evaluation shall include analysis of system reliability and involve close communication among Reliability Coordinators and the Energy Deficient Entity.

2.4.4 Initiating inquiries on reevaluating SOLs and IROLs. The Reliability Coordinators shall consult with the Balancing Authorities and Transmission Providers in their Reliability Areas about the possibility of reevaluating and revising SOLs or IROLs.

2.5 Coordination of emergency responses. The Reliability Coordinator shall communicate and coordinate the implementation of emergency operating responses.

2.6 Energy Deficient Entity actions. Before declaring an Alert 3, the Energy Deficient Entity must make use of all available resources. This includes but is not limited to:

2.6.1 All available generation units are on line. All generation capable of being on line in the time frame of the emergency is on line including quick-start and peaking units, regardless of cost.

2.6.2 Purchases made regardless of cost. All firm and non-firm purchases have been made, regardless of cost.

2.6.3 Non-firm sales recalled and contractually interruptible loads and demand-side management curtailed. All non-firm sales have been recalled, contractually interruptible retail loads curtailed, and demand-side management activated within provisions of the agreements.

2.6.4 Operating Reserves. Operating reserves are being utilized such that the Energy Deficient Entity is carrying reserves below the required minimum or has initiated emergency assistance through its operating reserve sharing program.

3. Alert 3 — Firm load interruption imminent or in progress. Circumstances:

• Balancing Authority or Load Serving Entity foresees or has implemented firm load obligation interruption. The available energy to the Energy Deficient Entity, as determined from Alert 2, is only accessible with actions taken to increase transmission transfer capabilities.

3.1 Continue actions from Alert 2. The Reliability Coordinators and the Energy Deficient Entity shall continue to take all actions initiated during Alert 2. If the emergency has not already been posted on the NERC website (see paragraph 2.1), the respective Reliability Coordinators will, at this time, post on the website information concerning the emergency.

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3.2 Declaration Period. The Energy Deficient Entity shall update its Reliability Coordinator of the situation at a minimum of every hour until the Alert 3 is terminated. The Reliability Coordinator shall update the energy deficiency information posted on the NERC website as changes occur and pass this information on to the affected Reliability Coordinators (via the RCIS), Balancing Authorities, and Transmission Providers.

3.3 Use of Transmission short-time limits. The Reliability Coordinators shall request the appropriate Transmission Providers within their Reliability Area to utilize available short-time transmission limits or other emergency operating procedures in order to increase transfer capabilities into the Energy Deficient Entity.

3.4 Reevaluating and revising SOLs and IROLs. The Reliability Coordinator of the Energy Deficient Entity shall evaluate the risks of revising SOLs and IROLs on the reliability of the overall transmission system. Reevaluation of SOLs and IROLs shall be coordinated with other Reliability Coordinators and only with the agreement of the Balancing Authority or Transmission Operator whose equipment would be affected. The resulting increases in transfer capabilities shall only be made available to the Energy Deficient Entity who has requested an Energy Emergency Alert 3 condition. SOLs and IROLs shall only be revised as long as an Alert 3 condition exists or as allowed by the Balancing Authority or Transmission Operator whose equipment is at risk. The following are minimum requirements that must be met before SOLs or IROLs are revised:

3.4.1 Energy Deficient Entity obligations. The deficient Balancing Authority or Load Serving Entity must agree that, upon notification from its Reliability Coordinator of the situation, it will immediately take whatever actions are necessary to mitigate any undue risk to the Interconnection. These actions may include load shedding.

3.4.2 Mitigation of cascading failures. The Reliability Coordinator shall use its best efforts to ensure that revising SOLs or IROLs would not result in any cascading failures within the Interconnection.

3.5 Returning to pre-emergency Operating Security Limits. Whenever energy is made available to an Energy Deficient Entity such that the transmission systems can be returned to their pre-emergency SOLs or IROLs, the Energy Deficient Entity shall notify its respective Reliability Coordinator and downgrade the alert.

3.5.1 Notification of other parties. Upon notification from the Energy Deficient Entity that an alert has been downgraded, the Reliability Coordinator shall notify the affected Reliability Coordinators (via the RCIS), Balancing Authorities, and Transmission Providers that their systems can be returned to their normal limits.

3.6 Reporting. Any time an Alert 3 is declared, the Energy Deficient Entity shall submit the report enclosed in this Attachment to its respective Reliability Coordinator within two business days of downgrading or termination of the alert. Upon receiving the report, the Reliability Coordinator shall review it for completeness and immediately forward it to the NERC staff for posting on the NERC website. The Reliability Coordinator shall present this report to the Reliability Coordinator Working Group at its next scheduled meeting.

4. Alert 0 - Termination. When the Energy Deficient Entity believes it will be able to supply its customers’ energy requirements, it shall request of its Reliability Coordinator that the EEA be terminated.

4.1. Notification. The Reliability Coordinator shall notify all other Reliability Coordinators via the RCIS of the termination. The Reliability Coordinator shall also notify the

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affected Balancing Authorities and Transmission Operators. The Alert 0 shall also be posted on the NERC website if the original alert was so posted.

C. Energy Emergency Alert 3 Report

A Deficient Balancing Authority or Load Serving Entity declaring an Energy Emergency Alert 3 must complete the following report. Upon completion of this report, it is to be sent to the Reliability Coordinator for review within two business days of the incident.

Requesting Balancing Authority:

Entity experiencing energy deficiency (if different from Balancing Authority):

Date/Time Implemented:

Date/Time Released:

Declared Deficiency Amount (MW):

Total energy supplied by other Balancing Authority during the Alert 3 period:

Conditions that precipitated call for “Energy Deficiency Alert 3”:

If “Energy Deficiency Alert 3” had not been called, would firm load be cut? If no, explain:

Explain what action was taken in each step to avoid calling for “Energy Deficiency Alert 3”:

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1. All generation capable of being on line in the time frame of the energy deficiency was on line (including quick start and peaking units) without regard to cost.

2. All firm and nonfirm purchases were made regardless of cost.

3. All nonfirm sales were recalled within provisions of the sale agreement.

4. Interruptible load was curtailed where either advance notice restrictions were met or the interruptible load was considered part of spinning reserve.

5. Available load reduction programs were exercised (public appeals, voltage reductions, etc.).

6. Operating Reserves being utilized.

Comments:

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Reported By: Organization:

Title: