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A New Jersey Nonprofit Corporation

Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com

NO R T H AM E R I C A N EL E C T R I C R E L I A B I L I T Y CO U N C I L Princeton Forrestal Vil lage, 116-390 Vil lage Boulevard , Pr inceton, New Jersey 08540-5721

Planning Committee

Wednesday, June 7, 2006 ⎯ 9 a.m. to noon (joint with OC)

Wednesday, June 7, 2006 ⎯ 1 to 5 p.m. Thursday, June 8, 2006 ⎯ 8 a.m. to noon

Sheraton St. Louis City Center Hotel & Suites

St. Louis, Missouri

(PLEASE BE PREPARED TO STAY FOR THE ENTIRE MEETING.)

Meeting Agenda

1. Administrative Matters a) Welcome and introductions b) Quorum *c) Antitrust Compliance Guidelines *d) PC Organization and Assignments

• PC subgroup appointments ⎯ Announce • New PC Executive Committee member including secretary ⎯ Action • PC roster update

e) Arrangements f) PC agenda ⎯ Approve *g) Minutes (w/o exhibits) of March 15–16, 2006 PC meeting ⎯ Approve *h) Minutes (w/o exhibits) of March 28 and highlights and minutes of May 2, 2006 Board

meetings *i) Minutes (w/o exhibits) of March 28 and May 1 Stakeholders Committee meeting (To

be provided.) j) PC chairman’s remarks *k) PC Executive Committee actions ⎯ Ratify 2. Resource Issues *a) Resource Issues Subcommittee ⎯ Information *b) Generating Availability Data System ⎯ Action

Business Casual Attire

Planning Committee Meeting Agenda June 7–8, 2006 St. Louis, Missouri 2

• Allow modification of pc-GAR to allow individual regional analysis where all

reports must have a minimum of three operating companies and seven units before any reports are prepared for printing and use.

3. Transmission Issues *a) Transmission Issues Subcommittee ⎯ Information *b) System Protection and Control Task Force ⎯ Action

• Approve the SPCTF’s updated report on “EHV Transmission System Relay Loadability Mitigation Update and Requests For Extensions and New Temporary Exceptions” (To be provided.)

• Approve the SPCTF’s proposed technical document, “Methods to Increase Line Relay Loadability” for publication and dissemination to the protective relaying community.

• Approve the SPCTF’s proposed technical document, “Switch-onto-Fault Schemes in the Context of Line Relay Loadability” for publication and dissemination to the protective relaying community. (To be provided.)

*c) Multiregional Modeling Working Group ⎯ Action • Review and approve recommended 2007 MMWG power flow and dynamics case

series. • Review and approve 2007 MMWG budget.

*d) Interconnection Dynamics ⎯ Discuss • Discuss how integrate the work of the Eastern Interconnection Phasor Project

Off-Line Applications Task Team (OLATT) and the comparable efforts in WECC into a comprehensive NERC interconnection dynamics analysis effort. (Bob Cummings to present)

*e) Transmission Availability Data Collection ⎯ Discuss • Dave Nevius to report on the status of discussions with EIA and others regarding

the creation of a transmission availability data base. *f) FERC NOPR on Proposed Revisions to Orders 888 and 889 ⎯ Discuss

• Discuss PC input for NERC response to FERC NOPR, especially on “Consistency and Transparency of ATC Calculations.”

4. Reliability Assessment Issues *a) Reliability Assessment Subcommittee ⎯ Information *b) Load Forecasting Working Group ⎯ Action

• Provide the LFWG and RAS with guidance on which data should be made available (and by when) to produce bandwidths for the reliability assessments and approve its use in the long term and seasonal assessments.

*c) Data Review Task Force ⎯ Information *d) Data Coordination Working Group ⎯ Information *e) Data Collection Issues ⎯ Discuss *f) Events Analysis Activities ⎯ Information

Planning Committee Meeting Agenda June 7–8, 2006 St. Louis, Missouri 3

5. Standards Issues *a) Standards Evaluation Subcommittee ⎯ Information *b) FERC Assessment of NERC Standards ⎯ Discuss

• Materials sent to committees and subgroups in advance of meeting; inputs from subgroup chairs and discussion by committees at the meeting.

*c) Functional Model Revisions ⎯ Discuss • Presented in general form in joint session; discussed in more detail in committee

meetings. (Stan Kopman to lead discussion.) 6. Compliance Issues *a) Compliance Review Group ⎯ Information 7. Role of the Committees *a) General considerations on role of PC and OC ⎯ Discuss

• Presented in general form in joint session; discussed in more detail in committee meetings.

*b) Straw proposal to rescope and restructure the PC and to provide support for the Reliability Assessment and Performance Analysis program ⎯ Discuss

*c) PC subgroup retirements ⎯ Action • Planning Reliability Model Task Force • Planning Standards Task Force • Blackout Recommendations Review Task Force • Data Review Task Force • ATC Task Force • Interconnection Dynamics Working Group • Wind Generation Task Force

8. Future Meeting a) Next PC meeting is scheduled for September 13–14, 2006 (location to be

determined). b) Agenda materials for this September meeting are due to the NERC staff on August 18, 2006. *Background material included.

Approved by NERC Board of Trustees, June 14, 2002 Technical revisions, May 13, 2005

A New Jersey Nonprofit Corporation Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com

N O R T H A M E R I C A N E L E C T R I C R E L I A B I L I T Y C O U N C I L Pr ince ton For res t a l V i l lage , 116-390 Vi l l age Bou leva rd , P r ince ton , New Je r sey 08540-5731

NERC ANTITRUST COMPLIANCE GUIDELINES I. GENERAL It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between or among competitors regarding prices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that unreasonably restrains competition. It is the responsibility of every NERC participant and employee who may in any way affect NERC’s compliance with the antitrust laws to carry out this commitment. Antitrust laws are complex and subject to court interpretation that can vary over time and from one court to another. The purpose of these guidelines is to alert NERC participants and employees to potential antitrust problems and to set forth policies to be followed with respect to activities that may involve antitrust considerations. In some instances, the NERC policy contained in these guidelines is stricter than the applicable antitrust laws. Any NERC participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NERC’s antitrust compliance policy is implicated in any situation should consult NERC’s General Counsel immediately. II. PROHIBITED ACTIVITIES Participants in NERC activities (including those of its committees and subgroups) should refrain from the following when acting in their capacity as participants in NERC activities (e.g., at NERC meetings, conference calls and in informal discussions):

• Discussions involving pricing information, especially margin (profit) and internal cost

information and participants’ expectations as to their future prices or internal costs. • Discussions of a participant’s marketing strategies. • Discussions regarding how customers and geographical areas are to be divided among

competitors. • Discussions concerning the exclusion of competitors from markets. • Discussions concerning boycotting or group refusals to deal with competitors, vendors or

suppliers.

Agenda Item 1cPC MeetingJune 7-8, 2006

Approved by NERC Board of Trustees, June 14, 2002 Technical revisions, May 13, 2005 2

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 and Bylaws are followed in conducting NERC business. Other NERC procedures that may be applicable to a particular NERC activity include the following:

• Reliability Standards Process Manual • Organization and Procedures Manual for the NERC Standing Committees • System Operator Certification Program

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.

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

NERC Planning Committee Organization and Assignments (July 1, 2005 to June 30, 2007)

Chairman: Scott M. Helyer Vice Chairman: Steven R. Herling

Secretary and Staff Coordinator: To be named

VOTING MEMBERS Regional Reliability Organization (RRO) Representatives

RFC-ECAR Paul B. Johnson

ERCOT William O. Bojorquez

FRCC To be named

RFC-MAAC John J. Moraski

RFC-MAIN Karl E. Kohlrus

MRO Kenneth H. Kuyper

NPCC William Longhi

SERC Shawn T. Abrams

SPP William (Bill) H. Dowling

WECC Ronald D. Schellberg Jeffrey Miller

Canada (East) Carmine Marcello

Canada (West) Neil J. Brausen

Canada and Market Segment Representatives Canada R.W. (Ron) Mazur Jean-Marie Gagnon

Cooperative Mike Risan Lane Mahaffey

Customer Daniel W. Griffiths Rick W. Meidel, Jr.

Federal (U.S.) Ronald E. Moulton Tim Ponseti

Independent Power Producer Juan R. Villar Barry Green

Invester Owned Utilities W. Perry Stowe James K. Robinson

ISO/RTO Jeffrey R. Webb Michael J. Henderson

Power Marketer Anthony Taylor Clayton Greer

State/Municipal Stuart Nelson Robert C. Williams

Transmission Dependent Utilities Christopher Plante Andrew W. Fusco

NONVOTING MEMBERS Regulator Representatives

Federal (United States) Paul Robb

State (Eastern) Philip Riley

State (Western) Lou Ann Westerfield

Federal (Canada) TBN

Canada (Provincial) Peter Fraser

Association Representatives APPA Michael J. Hyland

CEA Ralph Tedesco

EEI David A. Dworzak

EPRI Pei Zhang

EPSA Mark Bennett

NARUC TBN

NRECA Paul McCurley

NRC Thomas Koshy

Subgroup Chairs Scott M. Helyer (ExCom) Steven R. Herling (NomTF) Kevin J. Dasso (RAS) Mary H. Johannis (RIS) William O. Bojorquez (SES) Kenneth A. Donohoo (TIS)

Kenneth B. Keels, Jr. (DCWG) Navin B. Bhatt (IDWG) John M. Reynolds (LFWG) Mark J. Kuras (MMWG) Paul B. Johnson (ATC TF) James K. Robinson (BRRTF)

Paul B. Johnson (DRTF) Michael C. Raezer (PRMTF) Armando J. Perez (PSTF) Charles W. Rogers (SPCTF) William (Bill) H. Dowling (TATF) Mahendra Patel (WGTF) Navin B. Bhatt (CRG)

Agenda Item 1dPC MeetingJune 7-8, 2006

2

PC Liaisons

Sergio Garza (OC’s DAWG) To be named (OC’s RS) To be named (OC’s RS) Kenneth A. Donohoo (OC’s TS) Susan L. Morris (OC’s TS) Edward Pfeiffer (OC’s TS) To be named (OC’s IOSS) Peggy Ladd (OC’s IOSS) Executive Committee (ExCom) Scott M. Helyer (Chair) Steven R. Herling (Vice Chair) To be named Mike Risan (Cooperative) Jean-Marie Gagnon (Canada) To be named (Staff) Nominating Task Force (NomTF) Steven R. Herling (Chair) Paul B. Johnson (RFC-ECAR) Ronald D. Schellberg (WECC) Daniel W. Griffiths (Customer) Jeffrey R. Webb (ISO/RTO) To be named (Staff) Reliability Assessment Subcommittee (RAS)

Kevin J. Dasso (Chair) Masheed H. Rosenqvist (Vice Chair) Bernard M. Pasternack (RFC-ECAR) Kent Saathoff (ERCOT) John F. Odom, Jr. (FRCC) Mark J. Kuras (RFC-MAAC) Hoa Ngugen (MRO) John G. Mosier, Jr. (NPCC) H. Clay Young (SERC) Keith Tynes (SPP) James Leigh-Kendall (WECC) To be named (Canada) To be named (Cooperative) To be named (Customer) To be named (Federal) K.R (Chuck) Chakravarthi (IOU) To be named (IPP) John Lawhorn (ISO/RTO) To be named (PM) To be named (State/Municipal) To be named (TDU) To be named (Regulator) Robert Snow (FERC) To be named (OC Liaison) Poonum Agrawal (DOE Liaison) Jeffrey L. Mitchell (RFC-ECAR Alt.) Scott Beecher (FRCC Alt.) Glenn P. Catenacci (RFC-MAAC Alt.) Christopher Plante (MRO Alt.) William W. Lohrman (Staff) Shaun Streeter (Staff)

Resource Issues Subcommittee (RIS) Mary H. Johannis (Chair) To be named (Vice Chair) To be named (RFC-ECAR) Linda Shirey (ERCOT) John E. Odom, Jr. (FRCC) Thomas Falin (RFC-MAAC) Richard A. Voytas (RFC-MAIN) William Head (MRO) John M. Adams (NPCC) Garey C. Rozier (SERC) To be named (SPP) Ronald D. Schellberg (WECC) Kevan Jefferies (Canada) To be named (Cooperative) To be named (Customer) To be named (Federal) Matt Wolfe (IOU) Scott M. Helyer (IPP) Peter Wong (ISO/RTO) To be named (PM) To be named (State/Muni) To be named (TDU) John Lawhorn (RAS Liaison) To be named (OC Liaison) Peter Koegel (MRO Alt.) To be named (Staff) Standards Evaluation Subcommittee (SES) William O. Bojorquez (Chair) Michael C. Raezer (Vice Chair) To be named (RFC-ECAR) To be named (ERCOT) To be named (FRCC) Richard J. Kafka (RFC-MAAC) Edward C. Pfeiffer (RFC-MAIN) R.W. (Ron) Mazur (MRO) Ed Kremizer (NPCC) R. Scott Henry (SERC) To be named (SPP) To be named (WECC) David Kiguel (Canada) To be named (Cooperative) Daniel W. Griffiths (Customer) Mitchell Needham (Federal) Doug McLaughlin (IOU) Scott M. Helyer (IPP) Karl Tammar (ISO/RTO) To be named (PM) Sergio Garza (State/Muni) To be named (TDU) To be named (OC Liaison) To be named(Staff)

Transmission Issues Subcommittee (TIS) Kenneth A. Donohoo (Chair) To be named (Vice Chair) Bernard M. Pasternack (RFC-ECAR) Anthony Alford (ERCOT) Hector Sanchez (FRCC) William Whitehead (RFC-MAAC) Eric Mortenson (RFC-MAIN) Lloyd Linke (MRO) Thomas J. Gentile (NPCC) R. Douglas Powell (SERC) Jay Caspary (SPP) Sandra L. Johnson (WECC) Yury Tsimberg (Canada) To be named (Cooperative) To be named (Customer) To be named (Federal) W. Perry Stowe (IOU) Scott M. Helyer (IPP) Jeffrey R. Webb (ISO/RTO) To be named (PM) To be named (State/Muni) To be named (TDU) Paul McCurley (NRECA Observer) To be named (OC Liaison) Don Morrow (MRO Alt.) Stevey Corey (ISO/RTO Alt.) Robert W. Cummings (Staff) Data Coordination Working Group (DCWG)

Kenneth B. Keels, Jr. (Chair) Paul Kure (RFC-ECAR) Linda Shirey (ERCOT) Scott Beecher (FRCC) Mark Kuras (RFC-MAAC) Ray Mason (RFC-MAIN) Matt Couillard (MRO) Peter A. Koegel (MRO) Guy Zito (NPCC) Kathy Condon (NPCC) James P. Pratico (NPCC) Teresa Glaze (SERC) Brett Rollow (SPP) Jason Speer (SPP) Richard H. Simons (WECC) Timothy Egan (Canada) Diane Moody (State/Muni) Elsie S. Bess (EIA) Robert Schnapp (EIA) John Makens (EIA) Omar Elabbady (MRO Alt.) Shaun Streeter (Staff) William W. Lohrman (Staff)

3

Interconnection Dynamics Working Group (IDWG) Navin B. Bhatt (Chair - RFC-ECAR) Jose Conto (ERCOT) John W. Shaffer (FRCC) Mahendra Patel (RFC-MAAC) Franklin Bristol (MRO) Jason Weiers (MRO) Philip Tatro (NPCC) Lee Taylor (SERC) Donald D. Taylor (SPP) Les Pereira (WECC) To be named (Canada) To be named (Cooperative) To be named (IPP) To be named (Power Marketer) To be named (State/Municipal) To be named (TDU) Carson W. Taylor (Federal and IEEE Stability Controls Subcommittee Liaison) To be named (OC Liaison) Joseph M. Burdis (RFC-MAAC Alt.) John Seidel (MRO Alt.) Robert W. Cummings (Staff) Load Forecasting Working Group (LFWG)

John M. Reynolds (Chair – RFC-MAAC) Yves Nadeau (Vice Chair -NPCC-Canada) Bob Mariotti (RFC-ECAR) Art Ekholm (ERCOT) Leo Green (FRCC) Joel R. Gaughan (RFC-MAIN) Craig Kellas (MRO-Canada) Scott A. Loseke (MRO-U.S.) George McClure (MRO-Canada) John W. Pade (NPCC-U.S.) Paul J. Burke (NPCC-Canada) John L. Harris (SERC) Robert Shields (SPP) J. Chris Reese (WECC-U.S.) Henry Mak (WECC-Canada) To be named (IPP) To be named (Power Marketer) Hoa Nguyen (RAS Liaison) Craig Kellas (MRO Alt.) William W. Lohrman (Staff) Blackout Recommendations Review Task Force (BRRTF)

James K. Robinson (Chair - IOU) Scott M. Helyer (PC Vice Chair - IPP) Shawn T. Abrams (SERC) Ronald D. Schellberg (WECC) Jean-Marie Gagnon (Canada) Navin B. Bhatt (IDWG Chair) Mark J. Kuras (MMWG Chair) Charles W. Rogers (SPCTF Chair) Kirit S. Shah (TIS Chair) Donald M. Benjamin (OC Liaison) Larry J. Kezele (OC Liaison) Tom J. Vandervort (OC Liaison) Bob Stuart (Consultant) Tom Wiedman (Consultant) Robert W. Cummings (Staff)

Multiregional Modeling Working Group (MMWG) Mark J. Kuras (Chair) Rao Somayajula (RFC-ECAR) Robert J. O’Keefe (RFC-ECAR) Ganesh Velummylum (RFC-ECAR) Doug Evans (ERCOT) A.G. (Fred) McNeill (FRCC) Donal J. Kidney (NPCC) Robert W. Pierce (SERC) S.T. (Tom) Cain (SERC) Kirit Doshi (SERC) Rick L. Foster (SERC) Brett Rollow (SPP) Harvey B. Scribner (SPP) A.W. (Alex) Schnieder, Jr. (RFC-MAIN Alt.) Anthony Jablonski (RFC-MAIN Alt.) Ali Moshref (Dynamics Coord.) Louise McCarren (WECC Liaison) Brian M. Nolan (Staff) Available Transfer Capability Task Force (ATCTF)

Paul B. Johnson (Chair - ECAR) Lee Westbrook (ERCOT) To be named (FRCC) Bill Harm (RFC-MAAC) Ronald F. Szymczak (RFC-MAIN) Thomas C. Mielnik (MRO) To be named (Staff) Data Review Task Force (DRTF)

Paul B. Johnson (Chair) W. Perry Stowe (Vice Chair) Karl E. Kohlrus (PC RFC-MAIN) K.R. (Chuck) Chakravarthi (RAS-IOU) Hoa Nguyen (RAS-MRO) John E. Odom, Jr. (RAS-FRCC) Keith Tynes (RAS-SPP) Kenneth B. Keels, Jr. (DCWG Chair) Mark J. Kuras (DCWG RFC-MAAC) Paul Kure (DCWG RFC-ECAR) Richard Simons (DCWG-WECC) William W. Lohrman (Staff) Shaun Streeter (Staff) Transmission Avilability Task Force (TATF)

William (Bill) Dowling (Chair) Ken Kuyper (MRO) Jean-Marie Gagnon (Canada) James K. Robinson (IOU) W. Perry Stowe (IOU) To be named (Staff) Subject Matter Experts: Jeffrey R. Mitchell (RFC-ECAR) Michael E. Decesaris (RFC-MAAC) Brian Keel (WECC) Daryl McGee (IOU)

Planning Reliability Model Task Force (PRMTF) Michael C. Raezer (Chair - WECC) Douglas C. Collins (RFC-MAIN) Ken Kuyper (MRO) Stanley Kopman (NPCC) To be named (Canada) Mike Risan (Coop) To be named (Federal) To be named (TDU) Susan L. Morris (Member-at-Large) James Byrd (STIMP/CACTF Liaison) Roger C. Zaklukiewicz (NPCC Alt.) Dennis Chastain (Federal Alt.) To be named (Staff) Planning Standards Task Force (PSTF)

Armando J. Perez (Chair) Manjula Datta-Barua (ERCOT) John W. Shaffer (FRCC) Kenneth W. Braerman (RFC-MAAC) Mahendra C. Patel (RFC-MAAC) Gregory L. Pieper (MRO) Jeffrey R. Webb (ISO/RTO) To be named (Staff) System Protection and Control Task Force (SPCTF)

Charles W. Rogers (Chair) W. Mark Carpenter (Vice Chair) To be named (RFC-ECAR) To be named (ERCOT) John Mulhausen (FRCC) Joseph M. Burdis (RFC-MAAC) William J. Miller (RFC-MAIN) Deven Bhan (MRO) Philip J. Tatro (NPCC) Philip B. Winston (SERC) Fred Ipock (SPP) David Angell (WECC) John Ciufo (Canada-East) Bill Kennedy (Canada-West) To be named (Cooperative) To be named (Customer) Gary Kobet (Federal) Evan T. Sage (IOU) To be named (IPP) Jim Ingleson (ISO/RTO) To be named (PM) To be named (State/Muni) Keith Orsted (TDU) To be named (OC Liaison) Kevin Thundiyil (FERC) Robert B. Stuart (Investigation Team) Tom Wiedman (Investigation Team Alt.) Michael McDonald (Ameren( Henry Miller (RFC-ECAR Alt.) Albert N. Darlington (FRCC Alt.) Jon Sykes (WECC Alt.) Jon Daume (WECC Alt.) Baj Agawal (WECC Alt.) Robert W. Cummings (Staff)

4

Wind Generator Task Force (WGTF)

Mahendra Patel (Chair) Bob Singh (TIS/Canada) Beth Garza (TIS) Yuri Makarov (TIS) To be named (TIS) John M. Adams (RIS) David Angell (SPCTF) Joe H. Chau (SPCTF) David Jacobson (SES) Edward Kremzier (SES) Kevin J. Conway (OC) Charles Edey (CanWEA) Mark Scher (AWEA) Robert L. Sims (AWEA) Alan Myers (EEI) Brian F. Thumm (EEI) To be named (IEEE) Robert Zavadil (UWIG) Craig Quist (WECC) Jaison Tsikirai (WECC) Wayne Haidle (MRO) Rick Carson (SERC) Mark Lamothe (Canada) Juan R. Villiar (IPP) Ron Rebenitsch (NRECA) Edward C. Schrom, Jr. (Regulator) To be named (Staff)

Compliance Review Group (CRG)

Navin B. Bhatt (Chair) J. Richard Brackbill (RFC-ECAR) Franklin D. Bristol (RFC-MAIN) Quoc Le (NPCC) Mitchell E. Needham (SERC) Lee Taylor (SERC) Michael A. DeLaura (Staff)

Planning Committee

Chairman Scott M. Helyer Vice President, Transmission

Tenaska, Inc. 1701 East Lamar Blvd. Suite 100 Arlington, Texas 76006

(817) 462-1512 (817) 462-1510 Fx [email protected]

Vice Chairman Steven R. Herling

Vice President, Planning PJM Interconnection, L.L.C. 955 Jefferson Avenue Valley Forge Corporate Center Norristown, Pennsylvania 19403-2497


Secretary To Be Named

RRO ERCOT William O. Bojorquez

Director, System Planning Electric Reliability Council of Texas, Inc. 2705 West Lake Drive Taylor, Texas 76574

(512) 248-3036 (512) 248-6560 Fx bbojorquez@ ercot.com

RRO-FRCC To Be Named

RRO MRO Ken Kuyper

Senior Vice President Engineering & System Operations

Corn Belt Power Coop. 1300 13th Street, N. P.O. Box 508 Humboldt, Iowa 50548

(515) 332-2571 (515) 332-1375 Fx ken.kuyper@ cbpower.coop

RRO NPCC William Longhi

Vice President, System & Transmission Operations

Consolidated Edison Co. of New York, Inc. 4 Irving Place Room 1408 New York, New York 10003

(212) 460-1210 (212) 353-8831 Fx longhiw@ coned.com

RRO RFC Paul B. Johnson

Director-Transmission System Engineering & Maintenance Management

American Electric Power 700 Morrison Road Gahanna, Ohio 43230-8250

(614) 552-1670 (614) 552-1676 Fx pbjohnson@ aep.com

RRO-RFC John J. Moraski

Director Transmission & Interconnection Management

Baltimore Gas & Electric Company 7309 Windsor Mill Road Baltimore, Maryland 21244

(410) 597-7875 (410) 597-7674 Fx john.j.moraski@ bge.com

RRO RFC Karl E. Kohlrus

Supervisor, Electric Planning City Water, Light & Power of Springfield 1000 East Miller Street Springfield, Illinois 62702-5522

(217) 321-1391 (217) 789-2082 Fx Karl.Kohlrus@ cwlp.com

RRO SERC Shawn T. Abrams

Vice President of Planning and Power Supply

South Carolina Public Service Authority One Riverwood Drive, ECC P.O. Box 2946101 Moncks Corner, South Carolina 29461-6101

(843) 761-4067 (843) 761-7038 Fx stabrams@ santeecooper.com

RRO-SPP Bill Dowling

Vice President of Energy Management & Supply

Midwest Energy, Inc. 1330 Canterbury Hays, Kansas 67601

(785) 625-1432 (785) 625-1487 Fx bdowling@ mwenergy.com

Agenda Item 1dPC MeetingJune 7-8, 2006

2

RRO-WECC Jeffrey Miller Manager, Main Grid Transmission Planning

PacifiCorp 825 N. E. Multnomah Portland, Oregon 97232

(503) 813-5067 (503) 813-6893 Fx jeffrey.miller@ pacificorp.com

RRO WECC Ronald D. Schellberg

System Planning Leader Idaho Power Company 1221 West Idaho Street P.O. Box 70 Boise, Idaho 83707-0070

(208) 388-2455 (208) 388-6647 Fx rschellberg@ idahopower.com

RRO-Canada East Carmine Marcello

Director, System Development Hydro One, Inc. 483 Bay Street 15th Floor, North Tower Toronto, Ontario M5G 2P5

(416) 345-5300 (416) 345-5443 Fx carmine.marcello@ hydroone.com

RRO-Canada West Neil J. Brausen

Director, System Planning Alberta Electric System Operator 2500, 330-5th Avenue, S.W. Calgary, Alberta T2P 0L4

(403) 539-2533 (403) 539-2795 Fx neil.brausen@ aeso.ca

Canada Jean-Marie Gagnon

Project Manager Interconnected Networks Assets Planning

Hydro-Quebec TransEnergie Complexe Desjardins, Tour Est 10th Floor, CP 10 000 Montreal, Quebec H5B 1H7

(514) 289-2211 Ext. 2616 (514) 289-3234 Fx gagnon.jean-marie@ hydro.qc.ca

Canada R. W. Mazur

Manager, System Planning Department

Manitoba Hydro 12-1146 Waverly Street P.O. Box 815 Winnipeg, Manitoba R3C 2P4

(204) 474-3113 (204) 477-4606 Fx rwmazur@ hydro.mb.ca

Cooperative Lane T. Mahaffey

Director of Corporate Planning Seminole Electric Cooperative, Inc. P.O. Box 272000 Tampa, Florida 33688-2000

(813) 739-1253 (813) 264-7906 Fx lmahaffey@ seminole-electric.com

Cooperative Mike Risan

Senior Vice President, Transmission

Basin Electric Power Cooperative 1717 East Interstate Avenue Bismarck, North Dakota 58503-0564


Customer Daniel W. Griffiths

Senior Public Policy Research Analyst

Pennsylvania Office of Consumer Advocate 555 Walnut Street, 5th Floor Forum Place Harrisburg, Pennsylvania 17101-1923

(717) 780-4525 (717) 783-7152 Fx dgriffiths@ paoca.org

Customer Rick W. Meidel, Jr.

Vice President, Power Projects Exxon Mobil Power & Gas Services, Inc. 800 Bell Street CORP-EMB-3903H Houston, Texas 77002-2180

(713) 656-3201 (713) 656-7343 Fx rick.w.meidel@ exxonmobil.com

Federal Ronald E. Moulton

Regulatory & Restructuring Program Manager and Transmission Planning Manager

Western Area Power Administration MS G4400 P.O. Box 6457 Phoenix, Arizona 85005


Federal Timothy E. Ponseti

General Manager, Resource Planning & System Forecasting

Tennessee Valley Authority 1101 Market Street, MR-3H Chattanooga, Tennessee 37402

(423) 751-2699 (423) 751-8352 Fx teponseti@ tva.gov

3

IOU James K. Robinson Transmission Asset Manager Asset Mangement

PPL Electric Utilities Corporation 2 North 9th Street, GENN 5 Allentown, Pennsylvania 18101

(610) 774-4554 (610) 774-4678 Fx jkrobinson@ pplweb.com

IOU W. Perry Stowe

Director Transmission Planning Southern Company Services, Inc. Bin 13N-8183 P.O. Box 2641 Birmingham, Alabama 35291-8183

(205) 257-6138 (205) 257-1040 Fx wpstowe@ southernco.com

IPP Barry Green

Director, Markets and Research Ontario Power Generation Inc. 700 University Avenue, H18 G3 Toronto, Ontario M5G 1X6

(416) 592-7883 (416) 592-8519 Fx barry.green@ opg.com

IPP Juan R. Villar

Director Transmission Northeast Region

FPL Energy 700 Universe Boulevard Juno Beach, Florida 33408

(561) 694-3472 (561) 304-5161 Fx juan_r_villar@ fpl.com

ISO/RTO Michael I. Henderson

Director, Regional Planning and Coordination

ISO New England, Inc. One Sullivan Road Holyoke, Massachusetts 01040

(413) 535-4166 (413) 540-4203 Fx mhenderson@ iso-ne.com

ISO/RTO Jeffrey R. Webb

Director of Planning Midwest ISO, Inc. 701 City Center Drive Carmel, Indiana 46032

(317) 249-5412 (317) 249-5910 Fx jwebb@ midwestiso.org

Power Marketer Clayton Greer

Vice President, Regulatory Affairs

Constellation Energy Commodities Group 2030 Golden Bear Drive Round Rock, Texas 78664

(512) 921-7013 clayton.greer@ constellation.com

Power Marketer Anthony Taylor

Director, Transmission Services Williams Energy Marketing & Trading One Williams Center Tulsa, Oklahoma 74172

(918) 573-6183 (918) 573-6754 Fx anthony.taylor@ williams.com

State/Municipal Robert C. Williams

Director of Regulatory Affairs Florida Municipal Power Agency 8553 Commodity Circle Orlando, Florida 32819-9002

(407) 355-7767 (407) 355-5794 Fx bob.williams@ fmpa.com

State/Municipal Stuart Nelson

Manager, Asset Development Lower Colorado River Authority BTC-101 P.O. Box 220 Austin, Texas 78760-0220

(512) 369-4526 (512) 369-4413 Fx stuart.nelson@ lcra.org

TDU Andrew Fusco

Manager, Resource Planning Electricities of North Carolina, Inc. 1427 Meadowwood Blvd Raleigh, North Carolina 27604

(919) 760-6219 afusco@ electricities.org

TDU Christopher Plante

Director, Transmission Analysis WPS Resources Corp. 700 North Adams Street Green Bay, Wisconsin 54307

(920) 433-1290 (920) 433-1176 Fx CTPlante@ wpsr.com

NRC (Non-Voting)

Thomas Koshy Senior Electrical Engineer

Nuclear Regulatory Commission NRR/DE/EE1B Washington, D.C. 20555

(301) 415-1176 [email protected]

4

APPA (Non-Voting)

Michael J. Hyland Vice President, Engineering Services

American Public Power Association 2301 M Street, N.W. Washington, D.C. 20037-1484

(202) 467-2986 (202) 467-2992 Fx mhyland@ appanet.org

CEA (Non-Voting)

Ralph Tedesco Chief Operating Officer

Nova Scotia Power Inc. P.O. Box 910 Halifax, Nova Scotia B3J 2W5

(902) 428-6109 (902) 428-6990 Fx ralph.tedesco@ emera.com

NARUC (Non-Voting)

To Be Named

EEI (Non-Voting)

David A. Dworzak Manager, Transmission Policy

Edison Electric Institute 701 Pennsylvania Avenue, N.W. Washington, D.C. 20004


DOE (Non-Voting)

To Be Named

ELCON (Non-Voting)

To Be Named

EPRI (Non-Voting)

Pei Zhang Project Manager

Electric Power Research Institute 3412 Hillview Avenue Palo Alto, California 94304


EPSA (Non-Voting)

Mark E. Bennett Director of Policy

Electric Power Supply Association 1401 New York Avenue, N.W. 11th Floor Washington, D.C. 20005

(202) 628-8200 (202) 628-8260 Fx mbennett@ epsa.org

NASUCA (Non-Voting)

To Be Named

Regulator-Eastern (Non-Voting)

Philip Riley Advisory Engineer IV

Public Service Commission of South Carolina 101 Executive Center Drive Columbia, South Carolina 29210

(803) 896-5154 (803) 896-5231 Fx philip.riley@ psc.sc.gov

NRECA (Non-Voting)

I. Paul McCurley Manager, Power Supply

National Rural Electric Cooperative Association 4301 Wilson Boulevard MC EP11-252 Arlington, Virginia 22203-1860

(703) 907-5867 (703) 907-5517 Fx paul.mccurley@ nreca.coop

Regulator-Federal (United States) (Non-Voting)

Paul W. Robb Electrical Engineer

Federal Energy Regulatory Commission 888 First Street N.W. Washington, D.C. 20426

(202) 502-8856 (202) 219-1274 Fx paul.robb@ ferc.gov

Regulator-NEB (Non-Voting) (Non-Voting)

To Be Named

Regulator-Provincial (Canada) (Non-Voting)

Peter Fraser Special Advisor

Ontario Energy Board 2300 Yonge St., 26th Floor Toronto, Ontario M4P 1E4

(416) 440-7616 (416) 440-7656 Fx peter.fraser@ oeb.gov.on.ca

5

Regulator-Western (Non-Voting)

Lou Ann Westerfield Policy Strategist

Idaho State Public Utilities Commission P.O. Box 83720 Boise, Idaho 83720-0074

(208) 334-0323 (208) 334-3762 Fx lwester@ puc.state.id.us

Regulator-Texas (Non-Voting)

To Be Named

TransmissionIssues

Subcommittee (TIS)Chairman: Kenneth A. DonohooV. Chairman: To be named

ResourceIssues

Subcommittee (RIS)Chairman: Mary H. JohannisV. Chairman: To be named

ReliabilityAssessment

Subcommittee (RAS)Chairman: Kevin J. DassoV. Chairman: Masheed H. Rosenqvist

StandardsEvaluation

Subcommittee (SES)Chairman: William O. BojorquezV. Chairman: Michael C. Raezer

Data Coordination Working Group (DCWG)Chairman: Kenneth B. Keels, Jr.

Load Forecasting Working Group (LFWG)Chairman: John M. ReynoldsV. Chairman: To be named

Multiregional ModelingWorking Group (MMWG)Chairman: Mark J. KurasV. Chairman: To be named

Interconnection Dynamics Working Group (IDWG)Chairman: Navin B. BhattV. Chairman: To be named

Generating Availability Data System (GADS)Manager: G. Michael Curley

Planning Reliability Model Task Force (PRMTF)Chairman: Michael C. Raezer

Revised: January 6, 2006 to include new PC vice chairman.Revised: January 30, 2006 to include new LFWG chairman.Revised: January 30, 2006 to include TATF.Revised: May 25, 2006 to include new TIS chairman.

System Protection andControl Task Force (SPCTF)Chairman: Charles W. RogersV. Chairman: W. Mark Carpenter

Planning Committee Chairman: Scott M. Helyer

Vice Chairman: Steven R. Herling

Planning Standards Task Force(PSTF)Chairman: Armando J. Perez

Wind Generator Task Force (WGTF)Chairman: Mahendra Patel

Availability Transfer Capability Task Force (ATCTF)Chairman: Paul B. Johnson

Blackout Recommendations Review Task Force (BRRTF)Chairman: James K. Robinson

Data Review Task Force (DRTF)Chairman: Paul B. JohnsonV. Chairman: W. Perry Stowe

Compliance Review Group (CRG)Chairman: Navin B. Bhatt

Transmission Availability Task Force (TATF)Chairman: William (Bill) N. Dowling

Agenda Item 1d PC MeetingJune 7-8, 2006




Planning Committee Meeting

Phoenix Marriott Mesa

Mesa, Arizona

Wednesday, March 15, 2006 Thursday, March 16, 2006

Draft Minutes

Administrative Items Planning Committee (PC) Chairman Scott M. Helyer presided over the meeting of the NERC PC held Wednesday, March 15, 2006 from 1 to 6 p.m. and Thursday, March 16, 2006 from 8 to 11:20 a.m. in Mesa, Arizona. The meeting notice, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. Meeting presentations may be found in a separate file at http://www.nerc.com/~filez/pcmin.html. Quorum Of the PC’s 34 voting members, 32 members or their proxies were in attendance, exceeding the meeting quorum requirement of 23. The following proxies attended the meeting for absent PC members, which included: Jeffrey L. Mitchell (RRO-ReliabilityFirst Corporation ((MAIN)) for Karl E. Kohlrus (RRO-ReliabilityFirst Corporation (MAIN)), David Till (Tennessee Valley Authority) for Timothy E. Ponseti (Federal), Leonard York (Western Area Power Administration) for Ronald E. Moulton (Federal), Brian Gooder (Ontario Power Generation) for Barry Green (IPP), Guy Zito (Northeast Power Coordinating Council) for Michael I. Henderson (ISO-RTO), and Nathan Mitchell (American Public Power Association) for Michael J. Hyland (APPA). Antitrust Compliance Guidelines John R. Twitchell reviewed the NERC Antitrust Compliance Guidelines. New PC Subgroup Appointments Chairman Helyer announced the appointment of John M. Reynolds as chairman of the PC’s Load Forecasting Working Group. On the motion of Steven Herling, chairman of the PC Nominating Committee, the PC also elected John R. Twitchell as PC secretary. Approval of Agenda On the motion of Tom Washburn, the PC approved the agenda for the March 2006 PC meeting and granted Chairman Helyer the flexibility to reorder agenda items if he felt it appropriate.

Agenda Item 1gPC MeetingJune 7-8, 2006

http://www.nerc.com/~filez/pcmin.html

Planning Committee Meeting Minutes March 15–16, 2006 Mesa, Arizona 2

Approval of December 7–8, 2005 PC Meeting Minutes On the motion of Tom Washburn, the PC approved the minutes of the December 7–8, 2006 PC meeting as submitted. PC Executive Committee Actions On the motion of Ron W. Mazur, the PC ratified its executive committee actions to approve: the NERC Reliability Assessment Demand & Capacity Form Instructions; the 2006 PC Work Plan; the Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis in Response to NERC Blackout Recommendation 13c report; and, the Regional Evaluations of Undervoltage Load Shedding Programs in Response to NERC Blackout Recommendation 8b report. PC Written Reports The PC accepted written reports from the Load Forecasting Working Group, the Disturbance Analysis Working Group, the Data Coordination Working Group, the Multiregional Modeling Working group, the Data Review Task Force, the Compliance Review Group, the Wind Generation Task Force, and the Generation Availability Data System as submitted. Transition to the Electric Reliability Organization The PC extensively discussed the transition of NERC into the Electric Reliability Organization, as established by the Energy Policy Act of 2005. The PC focused on the options for a new NERC organization structure to accomplish the program goals defined for NERC by the Act. The PC chairman and vice chairman will consider the comments provided by the PC members at this meeting, and any future comments by the PC members, and coordinate with the Operating Committee chairman and vice chairman and NERC staff to define how to provide stakeholder technical expertise to the NERC reliability programs. Chairman Helyer emphasized that the status quo is not acceptable for the PC, and when the NERC program needs are better defined, the PC’s executive committee will review the scope and need for each PC subgroup, and any potential for streamlining PC activity. Further discussions on the role of the PC will be held at the June 2006 PC meeting. Reliability Assessment Subcommittee Kevin J. Dasso, chairman of the Reliability Assessment Subcommittee (RAS), provided the PC with an update on the progress and schedules for the summer 2006, winter 2006/2007, and long-term reliability assessments. (Presentation 1.) The first draft of the report on long-term issues that may impact the bulk electric system was reviewed by the PC, and input from the PC and the PC’s subgroups was solicited by RAS for inclusion in the issues section of the 2006 Long-Term Reliability Assessment report. Data Impacts of Companies Changing Regions Kevin J. Dasso, chairman of the Reliability Assessment Subcommittee, John M. Reynolds, chairman of the Load Forecasting Working Group (LFWG), and Kenneth B. Keels, chairman of the Data Coordination Working Group (DCWG), reviewed the issues related to the continuity of data for reliability studies caused by the recent realignment of regional reliability organizational membership after the formation of ReliabilityFirst Corporation. (Presentations 2 and 3.) On a motion by Jean-Marie Gagnon, the PC instructed the LFWG to continue to prepare load forecast bandwidths for the reliability regions with no membership changes utilizing LFWG’s current methodology. The LFWG should prepare load forecast bandwidths for reliability regions with membership changes through the exercise of sound engineering judgment.


Transmission Availability Task Force William H. Dowling, chairman of the Transmission Availability Task Force (TATF), reported on current industry practices for the collection of transmission system reliability information, and the transmission reliability data requirements of the new Schedule 7 of the Department of Energy’s Energy Information Administration (EIA) EIA-411 annual report. The TATF recommended that NERC is the appropriate entity to direct a comprehensive data collection and reporting process on transmission reliability. (Presentation 4.) On a motion by William Bojorquez, the PC accepted the TATF report and its recommendations, but conditioned implementation of the recommendations upon NERC obtaining EIA agreement to let a NERC data collection process replace the EIA Schedule 7 process, in order to avoid duplicate data collection processes. PC members Jean-Marie Gagnon and R. W. Mazur abstained from voting. The PC also stated that any data protocol developed for the collection of transmission system reliability information should be provided to the PC for review and approval. Transmission Issues Subcommittee Kirit S. Shah, chairman of the Transmission Issues Subcommittee (TIS), reviewed the TIS implementation plan for the recommendations in the report Regional Evaluations of Undervoltage Load Shedding Programs in Response to NERC Blackout Recommendation 8b. (Presentation 5.) Mr. Shah also reported that the reliability regions have all reported that the studies requested by the U.S.-Canada Power System Outage Task Force Recommendation 23, Strengthen Reactive Power and Voltage Control Practices in All NERC Regions, have been completed. NERC Reliability Standards Issues Kirit S. Shah, chairman of the Transmission Issues Subcommittee, and PC member James K. Robinson, described issues that had been raised about the adequacy of proposed NERC standard FAC-010-1, System Operating Limits Methodology, and footnotes “b” and “c” of Table I of NERC standards TPL-001-0, -002-0, and -003-0, System Performance. (Presentations 5 and 6, respectively.) On a motion by James Robinson, the PC approved the TIS recommendation to have standard FAC-010-1 continue to ballot as scheduled, and to have TIS provide comments related to footnotes “b” and “c” of Table I to the Assess Transmission Future Needs and Develop Transmission Plans standard drafting team. The motion also instructed TIS to conduct a Multiple Facility Trip survey of the NERC regions, and provide the PC with a recommendation about the appropriateness of a standard authorization request to modify FAC-010-1, should it be passed by the NERC ballot body. PC member Christopher Plante abstained from voting on this motion. Resource Issues Subcommittee Mary H. Johannis, chair of the Resource Issues Subcommittee (RIS), provided the PC with the status of RIS-sponsored standard authorization requests related to resource adequacy and to the reporting of fuel supply and delivery disruptions to generation. (Presentation 7.) Michael Curley, manager of the Generating Availability Data System, reported on selected fossil generating trends that indicate that owners of the aging fossil generation fleet are providing adequate maintenance, and preventing fossil generation performance from deteriorating. (Presentation 8.)


Standards Evaluation Subcommittee William O. Bojorquez, chairman of the Standards Evaluation Subcommittee (SES), provided the PC with a detailed update on the status and content of NERC standards under development. SES will be initiating an analysis of the existing body of NERC standards and will make recommendations to the PC on the need for new or revised standards if SES determines that there are gaps or if there are inadequacies in the standards. (Presentation 9.) William D. Blevins, NERC’s Manager of Business Practice Interface, reviewed the status of the ATC/TTC/AFC and CBM/TRM standard authorization requests. (Presentation 10.) System Protection and Control Task Force Charles W. Rogers, chairman of the System Protection and Control Task Force (SPCTF), reviewed the SPCTF’s recommendations on time extensions and temporary or permanent exceptions for mitigation efforts for zone 3 relay loadability contained in the SPCTF report EHV Transmission System Relay Loadability Mitigation Update and Requests Extensions and New Temporary Exceptions. (Presentation 11.) Relay loadability criteria was established by NERC Blackout Recommendation 8a, Improving System Protection. Mr. Rogers requested guidance for SPCTF from the PC on allowing schedule extensions to transmission protection system owners (TPSO) for completion of zone 3 relay mitigation activity. On a motion by Stuart Nelson, the PC approved the above mentioned SPCTF recommendations and report, with Guy Zito abstaining from voting. On a motion by Guy Zito, the PC approved providing latitude to the SPCTF through the exercise of good engineering judgment by SPCTF in approving changes in schedules by TPSOs for the completion of zone 3 mitigation activities. Virginia C. Sulzberger Recognition Former Planning Committee (formerly Engineering Committee) chairmen Jack C. Wells, Harlow R. Peterson, David A. Whiteley, Glenn B. Ross, and Armando J. Perez joined current PC Chairman Scott M. Helyer in recognizing retiring PC Secretary Virginia C. Sulzberger for her more that two decades of valuable service to NERC, the Planning Committee, and to the electric industry. Chairman Helyer also read congratulatory notes to Ms. Sulzberger from past PC chairmen Raymond M. Maliszewski, Jack D. Greenwade, and Richard F. Schmoyer. Next Meeting The next meeting of the Planning Committee is scheduled for June 7–8, 2006 in St. Louis, Missouri. Agenda materials for this June meeting are due to the PC secretary on May 12, 2006. Respectfully submitted,

John R. Twitchell John R. Twitchell PC Secretary


Board of Trustees Meeting

March 28, 2006

Princeton, New Jersey

Minutes Chairman Richard Drouin called to order a duly noticed special meeting of the North American Electric Reliability Council Board of Trustees on March 28, 2006 at 12:30 p.m. A copy of the meeting notice, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. Antitrust Compliance Guidelines Secretary Cook acknowledged the NERC Antitrust Compliance Guidelines. Appointment of Officers On motion by President Sergel, the board appointed Lynn P. Costantini, chief information officer, and Joseph K. Conner, Jr., chief financial officer, as additional officers of the corporation. Filings with the Federal Energy Regulatory Commission President Sergel began the discussion regarding NERC’s filing with the Federal Energy Regulatory Commission for certification as the electric reliability organization and for approval of standards with a list of key areas within the application that have had changes made to them from Draft II, or where significant issues were raised in the comments to Draft II.

• Definition of Statutory Versus Non-statutory Functions • Regional Standards • Regional Delegation Agreements • Settlement Agreements • Committees • Personnel Certification Governance Committee • Penalty Matrix • Right to Sue • Regional Budgets • The definition of “users of the bulk power system” and the Compliance Registry



Agenda Item 1hPC MeetingJune 7-8, 2006

President Sergel asked the stakeholders to send any written comments on the filings to Gerry Cauley by close of business Wednesday, March 29, 2006. The board discussed the comments they had heard at the Stakeholders Committee meeting earlier in the day and the presentation by Rick Sergel. On motion by Donald P. Hodel, the board approved for filing with the Federal Energy Regulatory Commission on April 4, 2006, the application for certification as the electric reliability organization and the petition for approval of reliability standards, substantially in the form presented to the board in the agenda materials. Filings with Governmental Authorities in Canada David Cook gave an overview of the electric reliability organization applications and notices and the requests for acceptance of the reliability standards and notices that NERC proposes to file with Alberta, British Columbia, Manitoba, New Brunswick, Nova Scotia, Ontario, Québec, Saskatchewan, and the National Energy Board in Canada. Following discussion, on motion by Ken Peterson the board approved the proposed filings for submittal to the respective jurisdictions in Canada substantially in the form presented to the board in the agenda materials. Creation of North American Electric Reliability Corporation David Cook asked the board to approve the creation of the North American Electric Reliability Corporation (“NERC Corporation”) as a necessary step in the formation of the electric reliability organization. On motion by Fred Gorbet the board approved the formation of NERC Corporation. Acknowledgements On motion of Sharon Nelson, the board congratulated and honored Rick Sergel, the entire NERC staff, and the body of stakeholders for their efforts in getting NERC to this momentous occasion. The board also acknowledged Mike Gent’s efforts on the legislation that made the filings possible. There being no further business, Chairman Drouin terminated the meeting at 1:25 p.m. Submitted by:

David N. Cook Secretary

Board of Trustees Draft Minutes 2 March 28, 2006



May 2, 2006

Washington, D.C.

Highlights President’s Report — President and CEO Rick Sergel reported that NERC’s application to become the electric reliability organization is the most pressing matter at this time. He also gave an account of five topics that NERC will be concentrating on in the next seven months: responding to FERC questions on reliability standards; clarifying compliance procedures; finalizing regional delegation agreements; establishing a compliance registry; and budgeting and funding of the ERO and regional entities for 2007. Reliability Standards Program ⎯ The board approved reliability standards in the following areas: Cyber Security; Coordinate Interchange; System Restoration Plans; Maintenance and Distribution of Dynamics Data Requirements and Reporting Procedures; Documentation of Data Reporting Requirements for Actual and Forecast Demands; Net Energy for Load; Controllable Demand-Side Management; and a regional difference for SPP on the Inadvertent Interchange Standard. The board also approved a resolution to implement the NERC-NAESB Procedure for Joint Standards Development and Coordination. Compliance Enforcement and Organization Registration and Certification Programs — The board heard reports on the 2005 Compliance Enforcement Program results; the results of vegetation outage reporting; and the status of organization registration. In general, compliance violations and reported vegetation outages in 2005 were similar to 2004. Reliability Readiness Audit and Improvement Program — The board received a report on the number of reliability readiness audits conducted to date; the total number of audits conducted since the program’s inception in 2004; and the status of audit recommendations. The ReliabilityFirst and ERCOT regions were cited for their efforts in providing volunteers to participate in out-of-region audits. Reliability Assessment and Performance Analysis Program — The board received reports on the preliminary results of NERC’s 2006 Summer Assessment; the status and preliminary findings of several event investigations; and plans to establish a reliability metrics



Agenda Item 1hPC Meeting June 7-8, 2006

Board of Trustees Highlights 2 May 2, 2006

and benchmarking program. NERC reported that it has placed Southern California, southwestern Connecticut, and the Powder River Basin coal delivery issue on its reliability “watch list.” Situation Awareness and Infrastructure Security — The board heard a report (as part of the Stakeholders Committee meeting on May 1) on NERC initiatives to utilize advanced technologies in order to enhance situational awareness of the condition of the bulk power system in North America. These initiatives were discussed in the context of the joint DOE-FERC report to Congress required by Section 1839 of the Energy Policy Act of 2005. Training, Education, and Personnel Certification Program ⎯ The board approved the revised System Operator Certification Program (to use continuing education hours instead of an examination for recertification) and the revised Continuing Education Program and Manual. Planning Committee — The board approved for implementation the recommendations of the Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis in Response to NERC Blackout Recommendation 13c report. Finance and Audit Committee — The board approved the 2004 and 2005 audited financials from Mercadien, P.C, along with the March 31, 2006 Treasurer’s Report. Consent Agenda ⎯ The board approved the consent agenda including: • Board of Trustees minutes of January 23, 2006 conference call; February 7, 2006 meeting;

and March 28, 2006 special meeting • Committee membership changes • Future meetings of May 1–2, 2007 in Washington, D.C., and changing the dates of the

February 5–6, 2007 meeting to February 12–13, 2007



May 2, 2006 Washington, D.C.

Draft Minutes

Chairman Richard Drouin called to order a duly noticed meeting of the North American Electric Reliability Council Board of Trustees on May 2, 2006 at 9 a.m. A copy of the meeting notice, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. Antitrust Compliance Guidelines Secretary Cook acknowledged the NERC Antitrust Compliance Guidelines. Executive Session The Board met in executive session from 7:45 a.m. to 8:15 a.m., without the chief executive officer present, to review management activities. Consent Agenda President Sergel presented the consent agenda with two additions, which the board approved, including: • Board of Trustees minutes of January 23, 2006 conference call; February 7, 2006 meeting;

March 28, 2006 special meeting. • Committee membership changes (Exhibit D). President’s Report President Sergel informed the board that the President’s Report will be a regular agenda item for future meetings. The report will be an opportunity for him to let the board know what pressing matters the NERC staff is working on. Rick reported to the board that the status of the ERO application is the most critical issue at this time. He also reported on five other areas of importance that NERC will be concentrating on for the next seven months: responding to FERC questions on reliability standards; clarifying compliance procedures; finalizing regional delegation agreements; establishing a compliance registry; and budgeting and funding of the ERO and regional entities for 2007.



Agenda Item 1hPC MeetingJune 7-8, 2006

Board of Trustees 2 Draft Meeting Minutes May 2, 2006

Reliability Standards Program Gerry Cauley, vice president and director of standards, presented several reliability standards for approval:

1. On the motion of James Goodrich, the board approved reliability standards CIP-002-1: Cyber Security ⎯ Critical Cyber Asset Identification; CIP-003-1: Cyber Security ⎯ Security Management Controls; CIP-004-1: Cyber Security ⎯ Personnel & Training; CIP-005-1: Cyber Security ⎯ Electronic Security Perimeter(s); CIP-006-1: Cyber Security ⎯ Physical Security of Critical Cyber Assets; CIP-007-1: Cyber Security ⎯ Systems Security Management; CIP-008-1: Cyber Security ⎯ Incident Reporting and Response Planning; CIP-009-1: Cyber Security ⎯ Recovery Plans for Critical Cyber Assets to become effective June 1, 2006 (with compliance monitoring to be staged in accordance with the associated implementation plan) and determined to retire the existing Urgent Action Cyber Security Standard (1200), effective June 1, 2006.

2. On the motion of Paul Barber, the board

a. Approved reliability standards INT-005-1: Interchange Authority Distributes Arranged Interchange; INT-006-1: Response to Interchange Authority; INT-007-1: Interchange Confirmation; INT-008-1: Interchange Authority Distributes Status; INT-009-1: Implementation of Interchange; INT-010-1: Interchange Coordination Exemptions to become effective January 1, 2007, in accordance with the associated implementation plan;

b. Approved modifications to reliability standards INT-001-1: Interchange Information

(replacing INT-001-0, revising requirements R1 and R2 and deleting requirements R3, R4, and R5); INT-003-1: Interchange Transaction Implementation (replacing INT-003-0, revising requirement R1 and deleting requirements R2, R3, R4, R5, and R6); and INT-004-1: Dynamic Interchange Transaction Modifications (replacing INT-004-0, deleting requirements R1, R2, and R3 and renumbering R4 to become R1), to become effective January 1, 2007, in accordance with the associated implementation plan: and

c. Determined to retire reliability standard INT-002-0: Interchange Transaction Tag

Communication and Assessment, effective January 1, 2007. 3. On the motion of James Goodrich, the board approved reliability standard EOP-005-1:

System Restoration Plans to become effective May 2, 2007, in accordance with the associated implementation plan, and determined to retire reliability standard EOP-005-0 effective May 2, 2007.

4. On the motion of Ken Peterson, the board approved reliability standard MOD-013-1:

Maintenance and Distribution of Dynamics Data Requirements and Reporting Procedure to become effective November 2, 2006, in accordance with the associated implementation plan, and determined to retire reliability standard MOD-013-0 effective November 2, 2006.

5. On the motion of Rick Sergel, the board approved reliability standard MOD-016-1:

Documentation of Data Reporting Requirements for Actual and Forecast Demands, Net Energy for Load, and Controllable Demand-Side Management to become effective

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/CIP-002-1.pdf














ftp://www.nerc.com/pub/sys/all_updl/standards/sar/Revised_Implementation_Plan_CIP-002-009_3Feb06.pdf

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/INT-005-1.pdf









ftp://www.nerc.com/pub/sys/all_updl/standards/sar/COORD_INTERCHNG_Plan_Pre-ballot.pdf




ftp://www.nerc.com/pub/sys/all_updl/standards/rs/EOP-005-1.pdf

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/EOP-005-1.pdf

ftp://www.nerc.com/pub/sys/all_updl/standards/sar/PhaseIII-IV_Impl_Plan_Set2_Pre-ballot_clean_15Feb06.pdf

ftp://www.nerc.com/pub/sys/all_updl/standards/rs/MOD-013-1.pdf








November 2, 2006, in accordance with the associated implementation plan, and determined to retire reliability standard MOD-016-0 effective November 2, 2006.

6. On the motion of Paul Barber, the board approved reliability standard BAL-006-1:

Inadvertent Interchange (adding a regional difference for the Southwest Power Pool to the existing standard BAL-006-0), to be effective coincident with the start of the Southwest Power Pool RTO market, currently scheduled for October 1, 2006. The modification to the standard to add the regional difference for the Southwest Power Pool is approved as an urgent action and will expire on May 2, 2007.

Gerry also reported that the initial ballot of proposed reliability standards FAC-010-1: System Operating Limits Methodology and FAC-011-1: Establish and Communicate System Operating Limits failed to reach quorum (73.4 percent of a required 75 percent of the ballot pool). The vote tabulation also indicates the standards were very close to not reaching the two-thirds majority necessary for approval. At the conclusion of the initial ballot the weighted affirmative vote was 68.3 percent. Given that nearly one-third of the ballot pool voted against the proposed standard because they thought it would weaken reliability rather than strengthen it, the drafting team has recommended withdrawing the proposed standards from the ballot process. The drafting team will revise the standards based on the comments received and post the revised standards for further public comment. Scott Henry, vice chairman of the Standards Authorization Committee (SAC), briefed the board on the activities of the SAC. He informed the trustees that the committee will present the “fill-in-the-blank” standards along with the standards process manual to the board for approval later this year. He also stated that the committee is working on completing the mission compliance elements in 22 standards and will be developing risk factors. Gerry Cauley then updated the trustees on the NERC-NAESB and ISO/RTO relationship. He stated that as more complicated standards are drafted, it becomes more difficult to determine if they fall under NERC rules (for reliability standards) or NAESB rules (for business practices.) In facing that reality, a NERC-NAESB Template Procedure for Joint Standards Development and Coordination document (Exhibit E) has been developed, and the NAESB board has approved the document. After discussion, on motion of Sharon Nelson, the board approved the following resolution:

RESOLVED, that NERC should implement the joint standards development procedure with the North American Energy Standards Board at this time.

Compliance Enforcement and Organization Registration and Certification Programs David Hilt, vice president and director of compliance, gave a report on the Compliance Enforcement Program and the Organization Registration and Certification Program and responded to questions from trustees.



Reliability Readiness Audit and Improvement Program Gerry Adamski, director of reliability readiness updated the board on the Reliability Readiness Audit and Improvement Program and responded to questions from trustees. Reliability Assessment and Performance Analysis Program David Nevius, senior vice president, introduced the three programs that comprise the Reliability Assessment and Performance Analysis Program: reliability assessments; events analysis and information exchange; and benchmarking. David gave a preview of the 2007 Summer Assessment and informed the trustees of areas of concern for the 2007 summer season: lower capacity margins in southern California; transmission constraints in southwestern Connecticut; and reduced coal deliveries from the Powder River Basin. Bob Cummings, director of events analysis and information exchange gave an overview of the Events Analysis and Information Exchange program. Jeff Norman, manager of benchmarking, reviewed the Benchmarking program with the trustees. Training, Education, and Personnel Certification Program Marty Sidor, director of training, education, and operator certification, reported on training and education, the shift to using continuing education hours system operator re-certification, and continuing education programs. On motion by Ken Peterson, the board approved the revised System Operator Certification Program and the revised Continuing Education Program and Manual. Standing Committee Reports Compliance and Certification Committee Ted Hobson, chairman, reported that the committee has had one meeting since the last board meeting. He also stated that the Compliance Policy and Procedures Subcommittee (CPPS) elected a new chairman, Greg Campoli, and vice chairman John Blazekovich. Ted informed the board that one of the CPPS’s duties will be to remove the compliance elements from the reliability standards, develop them separately, and bring them back before the board, along with the reliability standards, for approval. Critical Infrastructure Protection Committee Stuart Brindley, chairman, updated the board on CIPC projects. He stated that the cyber security standards are just the beginning of what needs to be addressed, and the industry needs to be educated on all aspects of critical infrastructure protection. He also said that the Secretary of Homeland Security has established a committee comprised of all critical industries to review critical infrastructure protection matters. CIPC will have their next meeting on June 20–21, in Arlington, Virginia. Operating Committee Sam Jones, chairman, reported that the committee had no items for formal approval, but continues to be active and work on the issues to bring before the board. He also gave an account of the events of April 17 that led to load-shedding in ERCOT.

Planning Committee Scott Helyer, chairman, asked the board to approve implementation of the recommendations from the report, Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis in Response to NERC Blackout Recommendation 13c. On motion by Paul Barber, the board approved the report and directed the Planning Committee to work with the NERC standards program to implement it. Regional Managers Bill Reinke, chairman, conveyed to the board that the regional managers are committed to making the ERO and delegation agreements work. The committee will be meeting with the NERC staff in a couple of weeks to discuss “fill-in-the-blank” standards. He also described a need for the six regions in the Eastern Interconnection to recreate the framework for conducting reliability assessments. Comments by Observers and Others A copy of the comments by observers and others is attached as Exhibit F. Board Committee Reports Finance and Audit Chairman Scherr reported that the committee met with the external NERC auditors to discuss the audit process, and the group approved the 2004 and 2005 audited financials. Chairman Scherr then moved that the board approve the audited statements, along with the Treasurer’s Report. He also informed the board that a new draft of the 2007 Business Plan and Budget will be out for a 30-day comment period at the end of May, and will be brought back before the board at their August 2, 2006 meeting. Compliance Chairman Goodrich updated the board on compliance issues and the readiness audit program. The committee will have their next meeting in July. Corporate Governance and Human Resources Chairman Anderson stated that the committee reviewed and approved a recommendation to approve dental benefits for NERC staff. There being no further business, Chairman Drouin terminated the meeting at 12:22 p.m. Submitted by,

David N. Cook Secretary


N O R T H A M E R I C A N EL E C T R I C R E L I A B I L I T Y C O U N C I L Princeton Forrestal Vil lage, 116-390 Vil lage Boulevard , Pr inceton, New Jersey 08540-5731

Stakeholders Committee Meeting

March 28, 2006

Princeton, New Jersey

Minutes Stakeholders Committee Vice Chairman William Ball called to order a duly noticed special meeting of the North American Electric Reliability Council Stakeholders Committee on March 28, 2006 at 10 a.m. The meeting announcement, agenda, and attendance list are attached as Exhibits A, B, and C, respectively. Introductions and Vice Chairman’s Remarks Vice Chairman Ball welcomed the members of the Board of Trustees, observers, and guests to the meeting. He stated that the purpose of the meeting was to provide input to the board on Draft III of NERC’s ERO application. Vice Chairman Ball announced the following proxies: Bill Chamberlain for Tim Newton (WECC) Julius Pataky for Dennis Maniago (Canada-at-Large) Allen Mosher for Bill Pippin (TDU) Audrey Zibelman for Gordon van Welie (ISO/RTO) Kim Warren for David Goulding (Canada-at-Large) Ken Wiley for Armando Olivera (FRCC) NERC Antitrust Compliance Guidelines Secretary Ellen Vancko acknowledged the Antitrust Compliance Guidelines. Statement by FERC Commissioner Vice Chairman Ball introduced Federal Energy Regulatory Commission (FERC) Commissioner Nora Mead Brownell. Commissioner Brownell stated that the effort to establish a North American electric reliability organization was the most important thing that FERC and the industry were doing, and that she and FERC were grateful for the hard work that NERC and the industry has done to create the new organization.



Agenda Item 1iPC MeetingJune 7-8, 2006

Discussion of NERC’s ERO Application Rick Sergel, NERC president and CEO thanked Commissioner Brownell for attending. He thanked the stakeholders for continuing to meet with NERC and talk about issues. He also gave kudos to the staff for their hard work for a job well done. President Sergel reviewed NERC’s ERO applications in the United States and Canada and the ERO filing schedule. He said that the ERO application documents demonstrate NERC’s ability to meet and exceed the requirements to become the ERO. President Sergel noted that the majority of the ERO document was unchanged from Draft III, but noted four places where the draft was changed in response to stakeholder comments: the definition of user, owner, operator; the penalties and sanctions matrix; the delegation agreement; and the ERO transition plan. Vice Chairman Ball then invited stakeholders to comment on the draft ERO application and express their opinions. Stakeholders offered comments on the areas identified by President Sergel as well as on other parts of the application where they had questions or concerns. Other areas where stakeholders expressed comments and concerns included: whether it was appropriate to codify the Personnel Certification Governance Committee in the bylaws; the need to distinguish between statutory and non-statutory ERO functions for budgeting purposes; the need to avoid remand of standards; the extent to which balanced decision making will need to extend within the subordinate structures of the ERO and regional entities; whether settlements of disputes should occur at the regional or ERO level; the role and structure of the operating and planning committees; the need to clearly define dispute resolution procedures; the need for consistency between the bylaws and rules of procedure; the need for fair and balanced representation of all stakeholders at the regional entity level as well as at the ERO level; and the need to ensure coordination and cooperation across government jurisdictions. Exhibit D is a letter submitted by the NPCC Executive Committee providing policy input to NERC’s draft ERO application. Board of Trustees Chairman Richard Drouin thanked the stakeholders for their work and active involvement in developing NERC’s ERO applications. He also thanked NAESB and the NERC observers for their participation and support. Adjournment There being no further business, Vice Chairman Ball adjourned the meeting at 12 p.m. Respectfully submitted,

Ellen P. Vancko Stakeholders Committee Secretary

Stakeholders Committee Minutes 2 March 28, 2006

Agenda Item 1k PC Meeting June 7–8, 2006

PC Executive Committee Actions The Planning Committee (PC) Executive Committee met by conference call on April 24, May 8, and May 23, 2006. On its April 24, 2006 conference call, the PC Executive Committee approved the 2006 Summer Assessment for presentation to the NERC Board of Trustees for approval to publish. Action Required: Ratify the PC Executive Committee’s approval of the 2006 Summer

Assessment.

Agenda Item 2a PC Meeting June 7–8, 2006

Resource Issues Subcommittee The chairman of the Resources Issues Subcommittee (RIS) respectfully submits the following report. A. Fuel Supply or Delivery Disruption Reporting SAR At the request of the Planning Committee (PC), the RIS drafted the subject standard authorization request (SAR), which was approved for posting by the Standards Authorization Committee (SAC). Industry comments were received by NERC during the comment period from January 16 through February 15, 2006. The SAC took steps to form a SAR drafting team to respond to industry comments and potentially revise the SAR. However, only three persons signed up for this team. In order to allow for a balanced cross-section of the industry to consider the comments on this SAR, the RIS decided to make the Fuel Supply or Delivery Disruption Reporting SAR the main topic for its regularly scheduled conference call on April 4, 2006. The three members of the SAR drafting team also participated in this call. Although, all of the participants in the conference call agreed that there is a need to develop and analyze information related to actual or potential generation outages caused by fuel delivery or supply disruptions, consensus could not be reached on how that information might best be collected in the context of this SAR. At this point, the participants in the call decided to approach the need for this information in a different way. They agreed that the regions are the appropriate entities to set up data collection processes to enable fuel supply/delivery interruption evaluations. Since the Resource Adequacy Assessment SAR, which is currently undergoing revision by its SAR drafting team in response to Round 2 of industry comments, already includes a provision to “identify risks to resource adequacy, such as the impacts, if any, of fuel supply interruptions”, the call participants concluded that the Resource Adequacy Assessment SAR is the appropriate vehicle to ensure the collection and analysis of fuel delivery or supply disruption information. Therefore, the RIS requested that the SAC withdraw the Fuel Supply or Delivery Disruption Reporting SAR. Action Required: None B. Mandatory GADS Reporting Even before the recommendation was made to the SAC to withdraw the Fuel Supply or Delivery Disruption Reporting SAR, members of the RIS had expressed doubts as to whether potential mandatory reporting of GADS data should be limited to reporting of fuel supply or delivery disruptions. Now, the RIS is actively investigating whether GADS reporting, or some part thereof, should be made mandatory, as suggested in Mike Curley’s1 “Proposal to Make Parts of GADS Mandatory for Use By the Resources Issues Subcommittee.” The RIS is evaluating which data is critical to assessing the adequacy of the bulk power system, as mandated in the

1 Mike Curley is the manager of GADS Services at NERC.

2

Energy Policy Act of 2005. If GADS is the best supplier of this critical data, then the RIS may recommend that portions of, or all of, GADS reporting become mandatory at a future PC meeting. Action Required: None C. RIS Comments to RAS on 2006 Long-Term Reliability Assessment (LTRA) In its first face-to-face meeting on March 16–17, 2006, the RIS discussed how it could best achieve the purposes of its charter. The RIS engaged in a brainstorming exercise on the best ways to assess resource adequacy on a North American, or at least, interconnection-wide basis consistent with that part of its charter, which calls for the RIS “to develop and evaluate methodologies for determining resource adequacy.” As a follow-up to that meeting, the RIS submitted comments to the Reliability Assessment Subcommittee with suggestions for improving the 2006 LTRA. Most of the suggestions revolved around shifting the assessment away from just reporting on projected loads, resources and reserve margins to a report on how well the various regions and sub-regions are complying with their resource adequacy criteria, where such have been established. This type of an assessment requires reporting on the way these areas measure resource adequacy (metrics) and how much they conclude is enough to be adequate (targets). For example, the assessment might need to focus on a loss-of-load probability (LOLP) metric and the target of 10%, or, at a minimum, describe how an LOLP of 10% is translated into a specific reserve margin requirement and report whether that requirement is met. Action Required: None Mary Johannis RIS Chairman May 18, 2006

Agenda Item 2b PC Meeting June 7–8, 2006

Generating Availability Data System G. Michael Curley, Manager-GADS Services, files the following items for discussion regarding NERC’s Generating Availability Data System (GADS): A. GADS 2005 Data Collection Update The 2005 data collection process is not complete but moving forward. At the time of this writing, GADS has complete and correct data on 93% of the units. Data continues to come in. NERC will close the data collection by the end of June 2006. Action Required: None B. Request to Modify the Rules for pc-GAR Several years ago, GADS Services introduced the pc-GAR software. One of the options in pc-GAR is to allow the users to pick regions for comparing themselves for reliability. Under the GADS Data Release Guidelines (last approved November 15, 2000) it states that “Unless expressly permitted in the following sections, data by power generator, pool, Region, or specific unit will be provided only with the authorization of the appropriate power generator, pool, or Region.” The Planning Committee approved that pc-GAR could offer regional data but only if the user picked two or more regions as one group, not individual regions. Generating companies are changing regional affiliations. With the creation of the ReliabilityFirst Corporation, one large region has replaced three smaller regions. The resulting changes have resulted in more requests for individual regional data. pc-GAR is designed to not print reports where there are less than three companies and less than seven units. This same rule could apply to regional data to insure that only groups of units within the region are provided in reports. GADS Services request that the PC reconsider the limit of regional data and allow individual regional data be available through pc-GAR, using the 3/7 rule. Action Required: Allow modification of pc-GAR to allow individual regional analysis

where all reports must have a minimum of three operating companies and seven units before any reports are prepared for printing and use.

G. Michael Curley Manager-GADS Services May 16, 2006


Transmission Issues Subcommittee The following status report was submitted by Ken Donohoo, new chairman of the Transmission Issues Subcommittee (TIS). Undervoltage Load Shedding Study Guidelines (Blackout Recommendation 8b) The NERC Board of Trustees, at its February 7, 2006 meeting, approved the implementation of the recommendations of the Review of Regional Evaluations of Undervoltage Load Shedding Capability in Response to NERC Blackout Recommendation 8b report and directed the PC to:

• develop by the end of 2006 a comprehensive set of study guidelines for use in future evaluations of the need and benefit of implementing undervoltage load shedding (UVLS) systems;

• review and report to the board at its August 2006 meeting on the regional UVLS implementation plans and schedules;

• survey the existing UVLS systems installed on the bulk power system, to continue to monitor future installations, and support potential future standards activities in this area; and

• survey the status of research and development efforts on methods to more accurately determine and model load characteristics and to report to the board at its November 2006 meeting on the results of those efforts.

The board also requested each regional reliability council, in conjunction with its members, to develop implementation plans and schedules to install UVLS capability in those load centers where regional studies have identified UVLS as feasible and beneficial to preventing instability and to provide these plans and schedules to the Planning Committee for review by June 2006; At the March 15-16, 2006 PC meeting, Kirit S. Shah, chairman of the TIS, reviewed the TIS plan and timetable for implementing the recommendations in the report. The current status of this work is:

• TIS developed draft study guidelines for undervoltage load shedding studies. After incorporating the comments received on the draft guidelines, TIS will forward the final guidelines to the PC for review and approval.

• TIS also sent the “Outage Survey and Existing UVLS Data Collection Survey” to the

regional managers on May 9, 2006, with a request for response by June 2. Concern has been expressed by some regions on the short response time and the format of the requested response. (The date for regional responses has been changed to June 30.)

2

Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis (Blackout Recommendation 13c) The NERC board approved for implementation the recommendations of the Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis in Response to NERC Blackout Recommendation 13c report. The 24 recommendations and associated implementation plans to improve planning processes and practices that relate to system reliability have been divided into two principal categories:

NERC Standards Activity — 11 recommendations to modify or clarify some of the existing NERC standards and standards currently going through the development process; and

Enhanced Practices — 13 recommendations to enhance existing practices. The recommendations included in this category are good practices related to procedural items. Incorporation of these recommendations by the regions and their members, as appropriate, could complement the NERC standards.

TIS will work with the NERC Standards Program to implement the first 11 recommendations. TIS sent the 13 “enhanced practices” recommendations to the regional managers on May 17 for consideration by the regions and their members. Action Required: None


System Protection and Control Task Force Charles W. Rogers, chairman of the System Protection and Control Task Force (SPCTF), assisted by Robert W. Cummings, NERC Director of Event Analysis and Information Exchange, will introduce and lead the discussion on the following items. A. Draft Standard Authorization Requests ⎯ Transmission Relay Loadability At the March 2006 Planning Committee (PC) meeting, the SPCTF presented a report, “EHV Transmission System Relay Loadability Mitigation Update and Requests For Extensions and New Temporary Exceptions,” (Attachment A) on the end-of-2005 entity reports on the mitigation of zone 3 nonconformances. The SPCTF report observed that some entities had not yet reported. Those entities have now reported, and the SPCTF report has been updated accordingly. Action Required: APPROVE the SPCTF’s updated report on “EHV Transmission System

Relay Loadability Mitigation Update and Requests For Extensions and New Temporary Exceptions.” (To be provided.)

B. Technical Document ⎯ “Methods to Increase Line Relay Loadability” At the December 2005 Planning Committee meeting, the PC approved an SPCTF technical document, “Increase Line Loadability by Enabling Load Encroachment Functions of Digital Relays.” This report addressed one specific approach to satisfying the zone 3 requirements by altering the nature of the distance relay characteristic. This report has been updated to address many more such methods, and has been re-titled as “Methods to Increase Line Relay Loadability.” This report (Attachment B) supersedes the earlier report. Action Required: APPROVE the SPCTF’s proposed technical document, “Methods to

Increase Line Relay Loadability” for publication and dissemination to the protective relaying community.

C. Technical Document ⎯ “Switch-onto-Fault Schemes in the Context of Line Relay Loadability” At the December 2005 Planning Committee meeting, the Blackout Recommendation Review Task Force recommended that Planning Committee subgroups address a number of additional issues related to the August 14, 2003 blackout as a result of the ongoing technical analysis. One of these recommendations was for the SPCTF to “Review the Response of Switch-onto-Fault Relay Functions to System Disturbances.” As a result of this recommendation from the BRRTF, the SPCTF has prepared a report, “Switch-onto-Fault Schemes in the Context of Line Relay Loadability.” (Attachment C)

2

Action Required: APPROVE the SPCTF’s proposed technical document, “Switch-onto-Fault Schemes in the Context of Line Relay Loadability” for publication and dissemination to the protective relaying community. (To be provided.)

D. Update on Other SPCTF Activities As a result of other recommendations from the Blackout Recommendation Review Task Force, other scope items from the original SPCTF charter, and other directed activities from the Planning Committee, there are a number of other ongoing or pending activities within the SPCTF. The SPCTF will present a brief summary of these other activities. Action Required: None

Copyright © 2006 by the North American Electric Reliability Council. All rights reserved. A New Jersey Nonprofit Corporation

Methods to Increase Line Relay Loadability

North American Electric Reliability Council

A Technical Document Prepared by the

System Protection and Control Task Force of the

NERC Planning Committee

Draft

May 2006

Attachment B (Agenda Item 3b)

Increase Line Loadability by Enabling Load Encroachment DRAFT

Page i

INTRODUCTION 1

RECOMMENDATION 8A RATIONALE AND METHODS TO ACHIEVE INCREASED LOADABILITY 1 1. INCREASE THE ANGLE OF MAXIMUM TORQUE (REACH) 2 2. CHANGE THE IMPEDANCE RELAY CHARACTERISTIC FROM A CIRCLE TO A LENS 3 3. ADD BLINDERS TO THE CHARACTERISTIC TO LIMIT REACH ALONG THE REAL AXIS 6 4. OFFSET ZONE 3 INTO THE FIRST QUADRANT 7 5. FOR A QUADRILATERAL CHARACTERISTIC, RESET THE RELAY 8 6. ENABLE THE LOAD ENCROACHMENT FUNCTION 8

Recommendation on Settings for the Load Encroachment Function 10 Load Encroachment Function Settings Example 10

CONCLUSION 12

APPENDIX A — FAULT RESISTANCE ASSESSMENT A-1 Using the Law of Tangents: A-1 Using the Law of Cosines: A-1

APPENDIX — SYSTEM PROTECTION AND CONTROL TASK FORCE B-1


Page 1

INTRODUCTION This Technical Document discusses the implementation of protective relaying functions to augment, reposition, and reshape, impedance relays to increase the loadability of relay settings without decreasing protection coverage. This informational guide was prepared by the NERC System Protection and Controls Task Force (SPCTF) and is intended to provide more insight into recommendations made to increase loadability.

This paper includes the November 2005 paper entitled Increase Line Loadability by Enabling the Load Encroachment (Appendix A), expanding on it by presenting additional methods for increasing relay loadability while still maintaining adequate protection. Like the Load Encroachment method, these techniques can be implemented after evaluating “Zone 3” loadability and “Beyond Zone 3” loadability.

RECOMMENDATION 8A RATIONALE AND METHODS TO ACHIEVE INCREASED LOADABILITY One of the observations made from the August 14, 2003 blackout was that protective relaying should not preclude operator action during extreme system emergencies. It was concluded that following an extreme contingency, the system operators should be allowed up to 15 minutes in which emergency actions, including load shedding, could be performed. To this end, a thermal rating relay loadability recommendation was established, namely 150% of the transmission line’s highest seasonal ampere circuit rating that most closely approximates a 4-hour winter emergency rating. This rating is representative of 15 minute emergency ratings already in use by some system operators. Two other system parameters are included in Recommendation 8a, an operational condition of a 0.85 per unit voltage and a power factor angle of 30 degrees (current lagging voltage). Similar to the thermal rating, the 0.85 per unit voltage was an observed value when the system was in an extreme condition, but not in a cascading mode. Similarly, the 30 degree power factor angle was also an observed value while the system was under stress. A 30 degree power factor angle is not an extreme value — some power lines operate at 45 degrees current lagging voltage.

The NERC SPCTF recognizes first and foremost that the power system must be protected. Secondly, that power system protection must not prevent operator action to save the interconnected power system. However, potential operator action is not the only consideration. There may be remedial action/special protection schemes that operate very quickly to restore the system to a secure operating state. These types of schemes don’t need 15 minutes, but, generally, only a number of seconds to take action before the zone distance relay times out and trips.

Several methods to increase loadability have been suggested:

1. Increase the angle of maximum torque (reach).

2. Change the impedance relay characteristic from a circle to a lens.

3. Add blinders to the characteristic to limit reach along the real axis.

4. For remote zone 3 protection, use an impedance relay offset into the first quadrant.

5. For a quadrilateral characteristic, reset the relay.

6. Enable the Load Encroachment Function of the relay.


Page 2

These techniques are easily demonstrated by example and by graphically plotting the changes to the relay characteristics from the basic mho characteristic. These techniques are presented with the assumption that the protective relay is a zone 3 relay with a remote backup settings criteria. However, these techniques can also be applied to other load-sensitive phase distance mho-type characteristics. Further, it is assumed that the appropriate local breaker failure relaying is installed, and that relay failure is covered by appropriate measures of redundancy. Figure 1 below represents a portion of a typical 345 kV transmission system. The intent is to show the need for remote zone 3, in the absence of other potential methods such as redundant communications, separate batteries, voltage transformers, etc., that may obviate the need for remote backup. For further details, refer to the NERC paper Rationale for the Use of Local and Remote (Zone 3) Protective Relaying Backup Systems - A Report on the Implications and Uses of Zone 3 Relays, dated February 2, 2005.

It should be noted that not all existing relays have all of the above mentioned techniques available as settings options. It is up to the relay settings engineer to choose the most appropriate technique(s). The most important point to understand is that the loadability recommendations are not absolute system conditions. They represent a typical system operation point during an extreme system condition. The voltage at the relay may be below the 0.85 per unit voltage and the power factor angle may be greater than 30 degrees. It is up to the relay settings engineer to provide the necessary margin as they do in all relay settings.

Figure 1 — 345 kV System Example

1. Increase the Angle of Maximum Torque (Reach) The method o increasing maximum torque angle is available for many electromechanical, electronic, and digital impedance relays. The mho-type relays have a maximum reach along an angle that typically is close to the angle of the transmission line impedance. This maximum reach angle is referred to as Maximum Torque Angle (MTA). This term is mechanically descriptive for electromechanical relays and has been functionally used to describe the angle of maximum reach for all mho type relays. Contact the relay manufacturer to determine the limits of MTA adjustment if the relay instruction book does not explicitly identify those limits. Increasing maximum torque angle is demonstrated graphically in Figure 2.

In the Figure 2 settings example, the zone 3 relay is being used primarily for remote backup. It is assumed the transmission line from A to B is properly protected by high speed relaying and backup relaying for all faults. The methods applied in this example to increase loadability apply equally to zone 1, zone 2, and the high speed impedance transmission line relays.

3

open

C

openA

CB fails to open

B

3 phase fault60 ohms

40 ohms

closed


Page 3

Figure 2 — Adjust Maximum Torque Angle to Increase Loadability

In this example, the remote end of the adjacent line section is covered with a 25% margin. This results in a 125 ohm setting along the angle of maximum torque. In this case the MTA is 75 degrees, a common angle for electromechanical relays. To increase line loading, the MTA angle can be adjusted on some relays as far as 90 degrees. With a 90 degree maximum torque angle, close-in faults involving fault impedance may not be detected; therefore, other relays may have to detect such faults. As indicated in the table in Figure 2, such adjustments can increase line loadability as measured along the 30 degree load apparent impedance line by 40%. If the applied relay has the capability of increasing MTA, this method maintains trip dependability while increasing loadability security with minimum cost implications.

2. Change the Impedance Relay Characteristic from a Circle to a Lens In the late 1970’s and early 1980’s, a need emerged for extremely fast operating protective relays to permit the installation of large base-load generators on the 200 kV and above transmission systems. These relays, with statistically measured operating times of 1 cycle, together with 2 cycle clearing circuit breakers, allowed for the reduction in fault clearing and critical clearing times necessary for the connection of these large units, typically 1,200 MW and above.

That vintage of protective relays was designed using discreet electronic components. Usually, they performed their measuring based on the comparison of operating and polarizing (reference) quantities. One method of protection using electronic relays was a mho distance type relay. That relay’s characteristic could easily be modified from a mho (circle) characteristic to a lens just by adjusting the coincident (characteristic) timer. The lens decreases the susceptibility an impedance-based relay has to tripping on stable power swings. Often that type of relay was adjusted from a mho to a lens to meet the transmission system owner’s requirements to maintain

T = 30 °ZMTA = 125 O

Trip MVA 345 kV2 Z30°

Change the Angle

Load Z 30°

Graph Lines

MTATripMVAZ30°

75°85°

90°

88O72O

63O

13521653

1889

Cos (MTA-?)Z30°ZMTACos (MTA-?)Z30°ZMTA

jX(ohms)

R (ohms)

30°

8a MVA

766937

1070

Trip MVA *8a MVA .85 1.5

For 30° Load Angle

Bus A

Bus B

Bus C

60 O

40 O


Page 4

immunity to recoverable power swings. The lens characteristic also accommodates more line loading as the example in Figure 3 demonstrates. Again, the manufacturer of the relay should be consulted before applying this method. It may be necessary to address the issues of speed and arc resistance accommodation with the manufacturer. A lens-type characteristic is offered in many digital relays. It is sometimes applied with an offset from the origin.

Figure 3 — Adjust Mho Circle to a Lens to Increase Loadability

Using the same system example from Figure 1, the loadability improvement due to the change in the characteristic shape of the relay can be measured by a decrease in load impedance along the 30 degree load line. The adjustment method is just an increase in coincidence (characteristic) timer setting within the electronic relay. From geometry, the angle inscribed within a lens will yield a constant angle. If the figure were a circle, the angle would be 90 degrees. For a lens, the angle is greater than 90 degrees. Any side of a triangle can be determined if one side and its angles are known using the law of sines. In this case, the side of interest is the one along the load line and the side known is the impedance along the maximum reach. Let the maximum torque angle be 75 degrees as in the first example. Let the angle of the lens be adjusted to be 120 degrees.

Load Z30°

60O

40O

Bus C

Bus B

Bus A

jX(ohms)

R (ohms)

Change the Characteristic

30°

Loadability improvement

Lens angle also called the characteristic angle

Load Z30°

60O

40O

Bus C

Bus B

Bus A

jX(ohms)

R (ohms)

Change the Characteristic

30°


Lens angle also called the characteristic angle


Page 5

Figure 4 — Calculate Lens Loadability

Then by the law of sines:

sin sinc b

C B=

Substituting the reach of the relay for c and the lens angle of 120 degrees for C, the impedance magnitude along the 30 degree angle line can be calculated as:

125sin120 sin15

bΩ=

° °

where b = 37.3 ohms.

From the table in Figure 2, this compares to an impedance of 88 ohms along the 30 degree load angle line for the remote zone 3 mho circle with MTA of 75 degrees. For a 345 kV line, a 37.3 ohms load impedance along the 30 degree load line corresponds to a trip MVA of 3,191 MVA and 1,808 MVA using NERC Recommendation 8a requirements of 0.85 pu voltage and 150% of the transmission line’s highest winter ampere circuit rating that most closely approximates a 4-hour rating.

Load Z 30°

30°

c

C

b

B

A

120°

45°

15°


Page 6

3. Add Blinders to the Characteristic to Limit Reach Along the Real Axis Most of the material in this section is drawn from IEEE Standard C37.113 Guide for the Protection of Transmission Lines. See that standard for a more extensive discussion of this topic.

Some manufacturers provide a relay element called a blinder that can be added in series with its mho relay to constrain operation along the R impedance axis. Others provide this function internally. Figure 5 depicts the blinder characteristic.

Figure 5 — Add Blinders to the Mho Characteristic

The increase in loadability can be set by adjusting the blinder closer to the origin. The relay will trip only if the measured impedance falls within the two blinders and the relay’s mho characteristic. The loadability improvement can be measured along the load line. Figure 5 shows the blinder with an angle paralleling the maximum reach line of the relay. This is because this relay element is often used to trip transmission lines for unstable swings while decreasing the likelihood of tripping for stable swings. The application is often used when it is known that an unstable swing will penetrate the protected transmission line. The blinder is used to initiate tripping for an unstable swing and logic is included to trip when the swing locus exits either the left or right blinder after sequentially passing through both blinders. This implies that the swing has passed through 180 degrees. An inherent advantage of this scheme is that the tripping will be initiated for a closing angle and therefore a decreasing recovery angle across the circuit breaker.

Add Blinders

Load Z 30°

jX(ohms)

R (ohms)

30°


Bus A

Bus B

Bus C

60 Ω

40 Ω


Page 7

4. Offset Zone 3 into the First Quadrant Relay loadability improvements are generally for relays that also respond to three phase faults. Some relays are packaged such that they have different elements that respond to phase-to-phase, three-phase, and phase-to-ground faults. In addition, there are some relay elements that respond to three phase faults only that can be offset from the origin. These elements have been included in electro-mechanical relays manufactured for many years and some digital relays also contain this function. Fully-offset mho relays are ideal for remote backup protection in that they are immune to line loading, as depicted in Figure 6. Their disadvantage is that a fully-offset mho relay will only cover a small portion of the protected line depending on the offset. They are truly applied as remote backup protection.

Figure 6 — Add a Remote Zone 3 Fully Offset Element

In this example, the remote backup relay (shown as a solid circle) is replaced by an offset zone 3 relay (shown as dashed circle) to provide the needed fault detection for the Figure 1 example. The zone 2 relay (also shown as a dashed circle) must be included as backup to protect the entire line. This protection, in total, takes on a classic “figure 8” configuration to replace the zone 3 from a coverage perspective. The measurement in improvement in loadability therefore, now depends on the zone 2 apparent impedance along the load line. From the example, zone 2 can be set 125% of the line impedance or 1.25 X 60 ohms = 75 ohms at 75 degrees. Then the Recommendation 8a trip MVA improves from 766 MVA to 1,272 MVA, using the equations of Figure 2.

R (ohms)

jX(ohms)

30°30°

Load Z 30°


Zone 2

Zone 3 offset

Offset Zone 3

Bus A

Bus B

Bus C

60 Ω

40 Ω


Page 8

5. For a Quadrilateral Characteristic, Reset the Relay Some digital relays allow the user to select a mho or a quadrilateral characteristic. Older electronic relays required the user to choose between a mho and a quadrilateral relay style. One of the settings is the reach of the relay along the R (resistive) axis. The impact of relay sensitivity to load and fault resistance is a part of the quadrilateral’s setting and application guides. For long lines, quadrilateral characteristics allow the user to set the relay as needed along the relay’s characteristic angle and then choose a resistive reach so as to minimize the impact of load encroachment while maintaining coverage for fault resistance. In this example, the resistive reach of the various relay zones are set independently of each other. Check your owner’s manuals to make sure this is true for the relay being reset.

Figure 7 — Reset Zone 3 Quadrilateral along the Resistive Axis

6. Enable the Load Encroachment Function The use of load encroachment function to increase relay loadability was first presented in the NERC SPCTF paper entitled Increase Line Loadability by Enabling the Load Encroachment, dated November, 2005. This section includes the discussion portion of the Load Encroachment white paper. The resistive reach discussion is included as an appendix.

Zone 1

Zone 2

Zone 3

Load Z 30°

Loadability improvement30°30°

jX(ohms)

R (ohms)

Reset Zone 3 Quadrilateral

Bus A

Bus B

Bus C

60 Ω

40 Ω


Page 9

Figure 8 — Enable the Load Encroachment Function

Enabling load encroachment features on existing relays will increase line loadability. The load encroachment function boundary line should not be set at exactly 30 degrees. Setting the boundary line for the load encroachment enabling angle exactly at 30 degrees creates a loadability discontinuity that could pose a threat to system security by allowing relay operation while the operator is performing the emergency switching operations. For instance, the load encroachment feature of the relay could be set at exactly 150% and 0.85 per unit voltage at a 30 degree power factor angle. A 1 or 2 degree difference in angle could cause the relay to operate much below the 150% requirement. During the August 14, 2003 disturbance, a 30 degrees power factor angle was observed prior to the unstable power swing between Michigan and Ontario. The 30 degree power factor angle observed may not be a maximum in future disturbances.

The margin recommended by the Blackout Investigation team is defined by a mho characteristic that accommodates 150% of the line rating at 85% voltage and 30 degree power factor angle. With this characteristic, there is no concern over minor variations in any of the quantities. Minor variations in the power factor angle become a concern only when a discontinuity is introduced by the load encroachment function. In order to mitigate this concern, a margin is recommended in setting the load encroachment function to keep the discontinuity at least 5 degrees from the conditions of concern observed on August 14, 2003.

There is some downside to widening the load encroachment arc in that the relay would be less sensitive to picking up for faults with very high arc resistance. However, the load encroachment should only be applied where three phase fault conditions with arc resistance is less of a concern, such as medium and long length transmission lines. For short transmission lines, there should be substantial margin between the setting of the relay and the loadability of the line without the need of a load encroachment function.

30°

35°


Load Z 30°

Add Load Encroachment

Bus A

Bus B

Bus C

60 Ω

60 Ω

10 Ω


Page 10

Recommendation on Settings for the Load Encroachment Function For the bulk electrical system 200 kV and above, the load encroachment feature should be set with its boundary line in the first quadrant between +35 and +45 degrees to take relay settings margin into consideration. This segment of the power system generally has lines with line impedance angles 75 degrees or greater. Forty-five degrees is the expected power factor angle at the theoretical maximum power transfer for steady state conditions, i.e. 90 degrees power flow angle across a transmission line1. This theoretical limit causes line currents to lag voltage by 45 degrees which corresponds to a relay measured impedance with angle of +45 degrees.

As relay engineers evaluate lower voltage lines in the “Beyond Zone 3” loadability review program, they may encounter critical lines at 100 kV to 200 kV with impedance angles considerably below 75 degrees, for example closer to 60 degrees. The need for relay margin exists for all relay settings. The use of load encroachment features for lower voltage lines should have at least a 5 to 10 degree margin relative to line angle. The following example describes one methodology to implement this recommendation.

Load Encroachment Function Settings Example Given the 345 kV system in the one line diagram in Figure 9, set a load encroachment function to work in conjunction with the zone 3 relay at bus A. Note Figure 9 is slightly different from Figure 1. This example demonstrates a calculation method to check for arc resistance accommodation.

Figure 9 — Load Encroachment Function Settings Example

The zone 3 relay at bus A is applied to the 60 ohm line. An adjacent line at bus B is also 60 ohms. The zone 3 relay at bus A is set at 150 ohms and 85 degrees to detect a three phase line end fault near bus C in the event that the common circuit breaker at bus B fails with a margin of 30 ohms. The line A-B loadability is 150% of the emergency thermal limit of the transmission line (150% of 2,000 amps = 3,000 amps) at a 0.85 per unit voltage, resulting in a load impedance of 57 ohms at 30 degrees. A load encroachment function is enabled to permit the emergency line current.

1 For a derivation of theoretical maximum power transfer which includes an explanation on the relationship of current angle with respect to voltage and on the relationship of voltage angle across a power system, see Appendix A, Exceptions, in the NERC document: Protection System Review Program Beyond Zone 3 available at www.NERC.com.

3 ph fault

60Ω

60Ω

Zone 3 = 150 Ω

cb fails

open

open

AB

CZsysA = 10 Ω

ZsysC = 10 Ω3 ph fault

60Ω

60Ω

Zone 3 = 150 Ω

cb fails

open

open

AB

CZsysA = 10 Ω

ZsysC = 10 Ω


Page 11

Figure 10 —Encroachment Settings on the R-X Diagram

The encroachment function eliminates a portion of the relay’s tripping circle in the area that will provide the necessary increase in line loadability. The magnitude of this improvement is indicated by the short line segment between the relay’s circle and the load encroachment characteristic. There is no impact to the relay’s reach along the maximum torque angle. However, fault resistance accommodation needs to be assessed. See Appendix A.

30°

10Ω

35°

Load60 Ω

60 Ω

150 Ω

57 Ω

43.8Ω

A

B

CLoadability

improvement

Arc Accommodation10

Ω

30°

10Ω

35°

Load60 Ω

60 Ω

150 Ω

57 Ω

43.8Ω

A

B

CLoadability

improvement

Arc Accommodation10

Ω


Page 12

CONCLUSION In the review of zone 3 relays completed December 31, 2004, the transmission protection owners reported that 17.3% of the 10,914 relay terminals reviewed required mitigation for conformance with the relay loadability requirements of NERC Recommendation 8a. However, only 2.6% of those terminals required equipment replacements. This technical paper describes many of the techniques relay practitioners used to increase loadability without the need for protective relaying equipment replacements. These measures were either intended to be permanent or intended be a part of a strategy designed to implement temporary exceptions as plans were implemented to reach a final technical solution.

The NERC SPCTF included the following discussion in its paper, “Relay Loadability Exceptions – Determination and Application of Practical Relaying Loadability Ratings:”

Temporary Exceptions

Temporary Exceptions allow for a delayed implementation schedule for facilities that require modification due to the inability to complete the work within the prescribed time frame because of facility clearance (equipment maintenance outages) or work force issues. Temporary exceptions may also be granted for application of temporary mitigation plans until full implementation can be achieved.

All applications for temporary exceptions should include sufficient justification for the delay in mitigation as well as a mitigation plan with a planned schedule for completion. For those facilities that are substantially outside the Recommendation 8A loadability requirements, the transmission protection system owner (TPSO) should have done everything practical with existing equipment to mitigate non-conforming relays and maximizing loadability before applying for temporary exceptions.

Such mitigation includes but is not limited to:

1. Elimination of unnecessary protection functions (beyond applicable protection needs)

2. Adjusting the maximum torque angle on the relay

3. Resetting of relays as possible while still meeting established protection practices

Every effort should be made to mitigate non-conforming critical lines as soon as possible on a priority basis.

It is essential that these strategies do not decrease transmission line and system protection while at the same time improving transmission system loadability security.

Increase Line Loadability by Enabling Load Encroachment Appendix A

A–1

APPENDIX A — FAULT RESISTANCE ASSESSMENT The degree of accommodation of arc resistance for a three phase arcing fault for any of the loadability improvement methodologies can be determined geometrically using the law of Tangents and Cosines. Refer to the section on load encroachment enabling for this particular example.

Figure A-1 —Determining Arc Resistance Accomodation

Using the Law of Tangents: In any triangle, the difference of any two sides is to their sum as the tangent of half the difference of the opposite angle is to half the sum of these angles.

( )( )

1tan 21tan 2

579535

Y Zy zy z Y Z

yYZ

−−=

+ +

= Ω= °= °

Solving for z, the distance from the relay where arc resistance is least accommodated:

32.8z = Ω

Using the Law of Cosines: The square of any side of a triangle equals the sum of the squares of the other two sides less twice the product of these two sides times their included angle.

2 2 2 2 cos( )5732.850

x y z yz XyzX

= + −= Ω= Ω= °

35°

35°50°

95°

X

B

y=57Ωz

xZY

35°

35°50°

95°

X

B

y=57Ωz

xZY

Increase Line Loadability by Enabling Load Encroachment Appendix A

A–2

In the equation below, x is a line segment that represents the deepest penetration of the load encroachment characteristic. It represents the magnitude of a three phase fault arc resistance

43.8arcx R= = Ω

Arc resistance is generally calculated using empirically determined equations, such as

440arcLR I= ×

where I is measured between 70 amps and 20,000 amps.

L is the measurement between conductors in feet. This is an empirical formula taken from the book: Protective Relaying – Principles and Applications by J. Lewis Blackburn. A similar empirical equation 1.48,750arc

LR I= × is presented by A.R. van Warrington in Applied

Protective Relaying. L is in feet, R is in ohms, and I is current measured between 1,000 and 30,000 amps.

Some practitioners consider the extension of the arc length with wind velocity and time if the fault is not cleared in high speed (0.2 seconds or less).

0 (3 )L L wind velocity time= + × ×

Velocity is measured in miles/hour, L is measured in feet. This empirical equation is provided in the Art and Science of Protective Relaying by Mason.

In this example, a 3-phase fault 32.8 Ω from the relay location at A results in the fault location with the least arc accommodation due to the deployment of the load encroachment function. The spacing between line conductors is 22 feet. Using 440arc

LR I= × , and assuming high speed

clearing the arc resistance would be 2.1 ohms. (Recalculating the 3 phase fault with the arc resistance included will not appreciably lower the current for a 2.1 ohm arc resistance.) Now assume a wind velocity of 30 mph and the fault persists for 1 second.

0 3 30 112L L feet= + × × =

Using this new arc length and 440arcLR I= × ,

112440 10.54,672arcR = × = Ω

(Recalculating the 3 phase fault with the arc resistance included will not appreciably lower the current for a 10.5 ohm arc resistance.)

It is possible that the arc resistance as detected by the relay at the origin could increase with in-feed from the other end of the line. For a fault at the end of the line from substation A – substation B, the arc resistance could be double, 21 ohms, in this example, which is still less than the 43.8 ohms identified on the figure. Finally, it is possible that the arc resistance can appear partly inductive to the relay at A due to differences in pre-fault voltage magnitudes and power flow. This can be considered in the margin calculation.

Increase Line Loadability by Enabling Load Encroachment Appendix B

B 1

APPENDIX B — SYSTEM PROTECTION AND CONTROL TASK FORCE

Charles W. Rogers Chairman / ECAR Representative

Principal Engineer Consumers Energy Co.

W. Mark Carpenter Vice Chairman / ERCOT Representative System Protection manager TXU Electric Delivery John Mulhausen FRCC Representative Florida Power & Light Co. Joseph M. Burdis MAAC Representative Senior Consultant / Engineer, Transmission and Interconnection Planning PJM Interconnection, L.L.C. William J. Miller MAIN Representative Consulting Engineer Exelon Corporation Deven Bhan MAPP Representative System Protection Engineer Western Area Power Administration Philip Tatro NPCC Representative Consulting Engineer National Grid USA Philip B. Winston SERC Representative Manager, Protection and Control Georgia Power Company Fred Ipock SPP Representative Senior Engineer – Substation Engineering City Utilities of Springfield, Missouri David Angell WECC Representative System Protection & Communications Leader Idaho Power Company

John L. Ciufo Canada Member-at-Large Team Leader – P&C / Telecom Hydro One, Inc. Jim Ingleson ISO / RTO Representative Senior Operations Engineer New York Independent System Operator Evan T. Sage Investor Owned Utility Senior Engineer Potomac Electric Power Company James D. Roberts Federal Electrical Engineer – Transmission Planning Tennessee Valley Authority Tom Wiedman NERC Blackout Investigation Team Consultant to NERC Henry Miller ECAR Alternate American Electric Power Baj Agrawal WECC Alternate Principal Engineer Arizona Public Service Company Michael J. McDonald Consulting Engineer Ameren Services Company Jon Sykes Senior Principal Engineer, System Protection Salt River Project Kevin Thundiyil Observer Federal Energy Regulatory Commission

Increase Line Loadability by Enabling Load Encroachment Appendix B

B 2

W. O. (Bill) Kennedy Canada Member-at-Large Principal Engineer Alberta Electric System Operator Bob Stuart NERC Blackout Investigation Team Principal T&D Consultant Elequant, Inc.

Robert W. Cummings Staff Coordinator Director of Event Analysis and Information Exchange North American Electric Reliability Council

Agenda Item 3c PC Meeting June 7–8, 2006

Multiregional Modeling Working Group Mark J. Kuras, chairman of the Multiregional Modeling Working Group (MMWG), submits the following five items for Planning Committee (PC) information and action. 2005 Final Budget Accounting The 2005 MMWG actual expenditures versus budget were: Deliverables Budgeted Actual 12 Power Flow cases $87,500 $82,658 5 Dynamics cases $95,000 $95,000 All cases were posted by the required due dates and all regions were deemed fully compliant. Action Required: None 2006 Compliance Plan accepted by Compliance and Certification Managers Committee The NERC Compliance and Certification Managers Committee accepted the 2006 MMWG Compliance Plan at its March 22–23, 2006 meeting. This plan includes due dates that will be evaluated for compliance to NERC Standards. NERC Planning Standard MOD-014 Due Dates Data Set I Due Dates Regional Coordinators submit solved power flow cases to AEP July 14, 2006 Regional Coordinators submit corrections to power flow cases to AEP September 8, 2006 Final Posting Date Data Set I power flow base cases (MOD-014) October 6, 2006 Data Set II Due Dates Regional Coordinators submit solved power flow cases to AEP August 11, 2006 Regional Coordinators submit corrections to power flow cases to AEP October 6, 2006 Final Posting Date Data Set II power flow base cases (MOD-014) November 3, 2006 NERC Planning Standard MOD-015 Due Dates Regional Coordinators submit initialized dynamic cases to Powertech October 13, 2006 Regional Coordinators submit corrections to dynamic cases to Powertech December 1, 2006 Final Posting Date dynamics base cases (MOD-015) December 29, 2006 Action Required: None

2

2006 Power Flow and Dynamics Base Case Series Work has begun on the 2006 base case series consisting of the following 12 power flow and five dynamics cases: Power Flow Dynamics 2007 Light Load 2007 Light Load 2007 Spring 2007 Summer 2007 Summer 2007 Fall 2007/08 Winter 2008 Spring 2008 Summer 2008 Summer 2008 Fall 2008/09 Winter 2008/09 Winter 2011 Summer 2011 Summer 2011/12 Winter 2016 Summer This base case series follows the same pattern as in 2005 but with each case incremented by one year. PSS/E Version 30 will be utilized to create these cases. No regional range changes will be utilized this year to allow time for some regions and NERC groups to advance to Revision 30 bus and area numbering capabilities. MMWG will continue to look for best practices in modeling and model validation. Deliverables 2006 Budget 12 Power Flow cases $85,500 5 Dynamics cases $95,400 Action Required: None 2007 Case Series This proposed base case series follows the same pattern as in 2006 but with each case incremented by one year. Two additional dynamics cases are recommended by MMWG to be created in 2007 as noted by asterisks below. Power Flow Dynamics 2008 Light Load 2008 Light Load 2008 Spring 2008 Summer 2008 Summer 2008 Fall 2008/09 Winter 2008/09 Winter 2009 Spring 2009 Summer 2009 Summer 2009 Fall 2009/10 Winter 2009/10 Winter* 2012 Summer 2012 Summer 2012/13 Winter 2012/13 Winter* 2018 Summer

3

The 2007 cases will utilize the new bus and area numbering capabilities of PSS/E Revision 30. Reallocation of regional bus and area ranges will be performed. Each region will have a minimum of 100,000 busses. Action Required: Review and approve recommended 2007 MMWG power flow and

dynamics case series. 2007 MMWG Budget Recommendations Deliverable 2007 Budget 12 Power Flow cases (increase due to PSS/E Rev 30) $96,250 5 Dynamics cases $95,400 MMWG Recommended Additional Dynamics Expenditures $19,000 Two Additional Dynamics Cases (2009/10 Winter and 2012/13 Winter) $8,000 Additional Database Enhancements for ½ Cycle Time Step Simulations $5,000 Addition of Relay Data into Database $32,000 Total Additional Dynamics Expenditures Action Required: Review and approve 2007 MMWG budget, including additional dynamics

expenditures.

Agenda Item 3d PC Meeting June 7–8, 2006

Interconnection Dynamics Bob Cummings, NERC Director of Events Analysis and Information Exchange, will discuss how the work of the Eastern Interconnection Phasor Project Off-Line Applications Task Team (OLATT) and comparable efforts in WECC might be combined into a comprehensive NERC interconnection dynamics modeling and analysis effort. A report on OLATT near-term tasks is attached (Attachment A). Action Required: None

1 Prepared By OLATT on May 19, 2006 (Contact: Navin Bhatt)

Eastern Interconnection Phasor Project - Off-Line Applications Task Team (OLATT):

Near-Term Tasks Based on OLATT discussions, and recent inputs from the EIPP Leadership Committee and the Executive Steering Group, the OLATT will initiate the following 3 PMU data analysis tasks immediately.

Task 1: Phasor Angle Analysis for Wide Area Situational Awareness This will be a joint task between OLATT & Real-Time Applications Task Team. Purpose: To explore the use of phasor angles in transmission operations environment.

Goals • Short-Term (2006): Begin to understand the behavior of phase angles across EI. • Mid-Term (2007-09): 1) Conduct rigorous technical analysis of phase angle data and

develop tools for system operators and planners. This would involve R&D efforts, perhaps in collaboration with academia and DOE labs. 2) Begin to utilize phase angle information in real time system operations environment.

• Long-Term (Beyond 2009): Utilize phase angle information in real time system operations environment.

Year 2006 Activities Subtask 1.1: Plot relative angles (using phase angle reference recommended by the

Performance Requirements Task Team) at all EI PMU locations. These plots should be developed on a continuous basis.

Subtask 1.2: Plot the phase angle differences among EI PMU locations. These plots should be developed on a continuous basis.

Subtask 1.3: Identify data quality issues, if any, and resolve them with the help of TVA and the Data Management Task Team.

Subtask 1.4: Analyze the above plots for trending of relative angles and angle differences at the PMU locations. This could be done by experienced system operators/planners/analysts, who should analyze the plots continuously to decipher the trends through correlation with known system events and topology changes.

Subtask 1.5: Identify those PMUs that are closely coupled electrically and follow the same phase angle trends.

Attachment A (Agenda Item 3d)


Subtask 1.6: Benchmark the PMU phase angle data with load flow results for various system events and topology changes.

Subtask 1.7: Conduct load flow simulations to predict phase angle differences among EI PMU locations for severe contingency conditions across EI. The simulation results would likely help in arriving at acceptable ranges of phase angle differences among various EI locations.

Subtask 1.8: Define R&D requirements for rigorous technical analysis of phase angle data. The R&D should be focused on converting phase angle data to information for use by system operators. Examples of such information include acceptable range of relative angle at each PMU location, as well as acceptable ranges of angle differences with respect to other PMU locations.

• Data Requirements: Accurately time-synchronized phase angle data for EI PMU

locations, with sampling rate of 1 sample per second. The TVA PDC houses the data required for this analysis. The accuracy of time synchronization of these data will have to be ascertained.

• Analysis Tools Required: Any plotting tool. The EIPP RTDMS is being enhanced

to include such plotting capability. • Deliverables in First Quarter 2007: 1) A white paper on use of phase angle data

within EI. 2) A list of R&D needs to facilitate the development of tools & techniques for system operators to use phase angle data.

Task 2: Small Signal Stability Analysis Purpose: To identify critical frequency modes in EI and their impact on power system.

Goals • Short-Term (2006): 1) Get familiarized with the tools & techniques to perform small

signal stability analysis using PMU data. 2) Identify dominant frequency modes and associated damping for system ambient conditions. 3) Identify dominant frequency modes and associated damping following the events leading to low frequency oscillations.

• Mid-Term (2007-09): Investigate modal behavior of the EI system for possible trends over time and for correlation with time of day, season, peak load, type of system event and other factors.

• Long-Term (Beyond 2009): Identify critical frequency modes and the impact of these modes on EI power system, and develop solutions to address these modes, as appropriate.


Year 2006 Activities Subtask 2.1: Learn to conduct small signal stability analysis of data collected by EI

PMUs. AEP and PNNL staff can facilitate this OLATT learning process. Subtask 2.2: Work with TVA and the Data Management Task Team to resolve data

quality issues. Subtask 2.3: Develop and implement an “event notification procedure.” This

procedure is to be used to notify all OLATT members, when any member learns of an event of interest.

Subtask 2.4: For each EI PMU, conduct small signal stability analysis of data collected during ambient conditions, i.e. during time periods involving no major system events such as a trip-out of a large generator. Identify the dominant modal frequencies and damping. Keep records of the results, along with associated time and date, to facilitate future correlation/trending efforts.

Subtask 2.5: For each EI PMU, conduct small signal stability analysis of data collected during the events involving low frequency oscillations. Identify the dominant modal frequencies and damping. Keep records of the results, along with associated time/date, triggering event and peak system load, to facilitate future correlation/trending efforts.

Subtask 2.6: Analyze the results of Subtasks 2.4 and 2.5 to develop an understanding of modal frequency behavior across the EI. Identify critical modal frequencies (observability) at various EI locations.

Subtask 2.7: Conduct simulation studies to benchmark above PMU data with simulation results.

• Data Requirements: Frequency (or power flow) data at all EI PMU locations, with

sampling rate of at least 10 samples per second (Recommended rate: 30 samples per second). TVA PDC data should be used for this task.

• Analysis Tools Required: Any signal-processing tool. Examples include DSI

Toolbox, Prony Analysis tool, EIPP RTDMS, etc. • Deliverables in First Quarter of 2007: 1) A report identifying ambient EI modal

frequencies and associated damping. 2) A report identifying dominant modal frequencies that occasionally get triggered on EI power system. 3) A white paper on observability of modal frequencies across EI.

Task 3: Primary Frequency (Governing) Response Analysis Purpose: To identify the trend of primary frequency (governing) response in EI.


Goals • Short-Term (2006): 1) Get familiarized with the tools & techniques to analyze the

primary frequency response of EI power system using PMU data. 2) Start analyzing and documenting the primary frequency response observed at various EI PMU locations.

• Mid-Term (2007-09): 1) Investigate primary frequency response of the EI system for possible trends over time and for correlation with time of day, season, peak load, type of system event and other factors. 2) Identify adverse impact, if any, of primary frequency response on EI power system and develop solutions to address such impact, as appropriate.

• Long-Term (Beyond 2009): Continue to monitor the primary frequency response of EI system.

Year 2006 Activities

Subtask 3.1: Learn to analyze primary frequency response of EI system, based on data collected by EI PMU s.

Subtask 3.2: Work with TVA and the Data Management Task Team to resolve any data quality issues.

Subtask 3.3: Develop and implement an “event notification procedure.” This procedure is to be used to notify all OLATT members, when any member learns of an event of interest.

Subtask 3.4: For each EI PMU, analyze primary frequency response. Keep records of the results, along with associated time/date, triggering event and peak system load, to facilitate future correlation/trending efforts.

Subtask 3.5: Analyze the results of Subtasks 3.4 to develop an understanding of trend of EI primary frequency response.

Subtask 3.6: Use above information to improve modeling of governing response in simulation studies.

• Data Requirements: Frequency data at all EI PMU locations, with sampling rate of

30 samples per second. TVA PDC data should be used for this task. • Analysis Tools Required: Any plotting program. • Deliverables in First Quarter of 2007: 1) A report documenting EI primary

frequency response in MW per 0.1 Hz. 2) Preliminary observation on trend of EI primary frequency response.


Roles & Responsibilities Role Responsible Individual(s) Overall Coordination Navin Bhatt (OLATT; AEP) Coordination of Task1 Terry Bilke (Real Time Applications

Task Team; MISO) Coordination of Task 2 A member of MISO Small Signal

Stability Task Force Coordination of Task 3 Dean Ellis (NYISO) Data Management & Quality Manu Parashar (EPG) and Ritchie

Carroll (TVA) Data Analysis Tools & Procedures Sanjoy Sarawgi (AEP), Yuri

Makarov (PNNL) Load Flow Studies Mahendra Patel (PJM) Small Signal Stability Studies Sujit Mandal (Entergy) Event Notification Procedures Bob Cummings (NERC) Preparation of Study Results, Deliverables and Reports

Agenda Item 3e PC Meeting June 7–8, 2006

Transmission Availability Data Collection At its March 15–16, 2006 meeting, the Planning Committee (PC) accepted the report and recommendations of its Transmission Availability Task Force (TATF) regarding NERC’s role in directing a comprehensive data collection and reporting process on transmission availability data. However, the PC conditioned implementation of the recommendations upon NERC obtaining Energy Information Administration (EIA) agreement to let a NERC data collection process replace the EIA Schedule 7 process, in order to avoid duplicate data collection processes. NERC staff discussed this issue with representatives of EIA, but was unable to gain EIA’s agreement to suspend the Schedule 7 reporting requirements, primarily because these requirements had already been approved by OMB. It is NERC staff’s opinion that NERC will need to demonstrate that it has established a system for collecting transmission availability data before EIA will rescind its Schedule 7 reporting requirements. Therefore, staff recommends that the PC proceed to implement the recommendations of its TATF by establishing a task force whose responsibility shall be to design the transmission availability report format and statistical information to be published, and then the specific data collection protocols required to develop such reports. The task force should be directed to coordinate its efforts with those of other organizations involved in setting definitions for reporting and analyzing transmission availability data, including the Canadian Electricity Association, Electric Power Research Institute, and IEEE. (An IEEE group is currently working on revisions to Standard 859 — “IEEE Standard Terms for Reporting and Analyzing Outage Occurrences and Outage States of Electrical Transmission Facilities.”) Action Required: Discuss

Agenda Item 3f PC Meeting June 7–8, 2006

FERC NOPR on Proposed Revisions to Orders 888 and 889 On May 18, 2006, the Federal Energy Regulatory Commission proposed amendments to regulations adopted in Order Nos. 888 and 889 to ensure transmission services are provided in a nondiscriminatory and just and reasonable basis. Among the OATT reforms the Commission is proposing in its NOPR are changes regarding consistency and transparency of ATC calculations. From the Commission press release (Attachment A):

CONSISTENCY AND TRANSPARENCY OF ATC CALCULATIONS. The absence of a consistent methodology to determine available transfer capability (ATC) provides discretion to transmission providers to deny service to competitors. The Commission proposes to make certain elements of ATC more consistent, and directs public utilities, working through the North American Electric Reliability Council, to address identified areas of concern. It also increases the transparency of ATC calculations through additional pro forma OATT requirements and postings on the open-access same-time information systems (OASIS) required under Order No. 889.

Copies of the NOPR fact sheet (Attachment B) and proposed changes to Open Access Transmission Tariff Attachment C – “Methodology to Assess Available Transfer Capability” (Attachment C) are included for information. NERC is in the process of developing revisions to its current standards on transfer capability. The proposed changes to existing modeling standard(s) would add a requirement for transmission providers to coordinate the calculation of TTC/ATC/AFC and requires that specific reliability practices be incorporated into the TTC/ATC/AFC calculation and coordination methodologies. According to the SAR, such changes will enhance the reliable use of the transmission system without needlessly limiting commercial activity. The proposed changes also add a requirement for documentation of the methodologies used to coordinate TTC/ATC/AFC, and a requirement for the enhanced documentation of the calculation methodology. The PC will discuss input for NERC’s response to the NOPR. Action Required: Discuss

FEDERAL ENERGY REGULATORY COMMISSION

WASHINGTON, D.C. 20426

NEWS RELEASE NEWS MEDIA CONTACT: FOR IMMEDIATE RELEASE Bryan Lee May 18, 2006 202-502-8680 Docket Nos. RM05-25-000 &

RM05-17-000

PROPOSED CHANGES TO OPEN-ACCESS RULES AIM TO IMPROVE CLARITY, TRANSPARENCY OF TRANSMISSION USE & PLANNING

The Federal Energy Regulatory Commission today proposed amendments to

regulations adopted in Order Nos. 888 and 889 to ensure transmission services are provided in a nondiscriminatory and just and reasonable basis. The proposal marks the first major reform of the open-access transmission tariff (OATT) enacted 10 years ago.

“We act today to strengthen the OATT and address deficiencies that have become apparent over the decade since its adoption, particularly in the areas of ATC calculation and transmission planning,” said Commission Chairman Joseph T. Kelliher. “These reforms will ensure that the OATT achieves its original purpose – remedying undue discrimination in the provision of transmission service. The reforms are not, however, designed to create new market structures, divest control over transmission, impinge on state jurisdiction, or weaken the protection of native load customers.”

The Commission concluded as long ago as December 1999, in Order No. 2000,

that transmission providers retained the incentive and ability to discriminate against third-party users of their transmission systems, particularly in areas where the pro forma OATT left the transmission provider with significant discretion. In Order No. 2003, the Commission similarly found that interconnection requirements could be used to discriminate. Today’s notice of proposed rulemaking (NOPR) is another action by the Commission designed to enhance the regulatory framework established in Order No. 888 and Order No. 889.

The Commission received more than 4,000 pages of initial and reply comments in

response to its September 2005 Notice of Inquiry (NOI) seeking comment on necessary reforms of the Order No. 888 pro forma OATT.

“In proposing to reform Order No. 888, we have relied heavily on the comments,”

the Commission said in today’s NOPR, calling the comments received on that NOI and another on calculating available transmission transfer capability “informative and useful.”

Attachment A (Agenda Item 3f)

Through the new OATT embodied in today’s proposal, the Commission seeks to increase transparency and clarity in the planning and use of the transmission system while addressing ambiguities in the original pro forma OATT. The lack of specificity in the pro forma OATT creates opportunities for discrimination and makes discrimination more difficult to detect when it does occur, the Commission said.

Among the OATT reforms the Commission is proposing are the following:

- CONSISTENCY AND TRANSPARENCY OF ATC CALCULATIONS. The absence of a consistent methodology to determine available transfer capability (ATC) provides discretion to transmission providers to deny service to competitors. The Commission proposes to make certain elements of ATC more consistent, and directs public utilities, working through the North American Electric Reliability Council, to address identified areas of concern. It also increases the transparency of ATC calculations through additional pro forma OATT requirements and postings on the open-access same-time information systems (OASIS) required under Order No. 889.

- TRANSMISSION PLANNING, REGIONAL COORDINATION AND TRANSPARENCY. Vertically integrated utilities lack the incentive to relieve transmission constraints in a nondiscriminatory manner, and existing planning processes lack transparency, each of which contributes to potential undue discrimination in, and otherwise creates barriers to, infrastructure development. The Commission proposes to require transmission providers to participate in an open and transparent regional transmission planning process that adheres to the NOPR’s planning principles.

- TRANSMISSION PRICING. The Commission proposes to reform pricing policies related to imbalances, credits for customer-owned transmission facilities and capacity reassignment.

- NON-RATE TERMS AND CONDITIONS. The NOPR proposes to revise the rules under which a transmission provider must provide rollover rights, and proposes to require the provision of hourly firm point-to-point service. The Commission also concludes that existing methods of evaluating requests for long-term point-to-point service may no longer be just, reasonable and may be unduly discriminatory. The NOPR proposes that transmission providers must use all available redispatch options to satisfy a request for firm point-to-point services and, at the transmission customer’s option, study redispatch options before the customer is obligated to incur the costs and delays of a transmission facilities study.

- INCREASED TRANSPARENCY. In addition to the ATC and planning reforms, the Commission proposes to require transmission providers to post all business rules, practices and standards on OASIS, and to include credit review procedures in their OATT. The NOPR also would require transmission providers and network customers to use the OASIS to request designation of a new network resource and to terminate the designation of an existing resource.

- ENFORCEMENT. The Commission proposes that transmission providers post on

OASIS specific performance metrics related to their completion of required studies to evaluate transmission requests. The NOPR also proposes operational penalties and addresses the treatment of operational penalty revenues. The NOPR retains the use of functional unbundling in conjunction with the OATT

to promote competitive wholesale power markets and reduce barriers to market entry through the control of transmission, but does not impose any particular market structure on the industry.

The Commission also reaffirms many of the core elements of Order No. 888:

- COMPARABILITY. The NOPR retains the comparability requirement, in which third-party users of the transmission system must be dealt with in a manner comparable to the transmission owner’s use of the system.

- SERVICES. The Commission proposes to retain the two forms of transmission service, network and point-to-point.

- NATIVE LOAD. The NOPR retains the protection of native load customers embodied in Order No. 888, consistent with the new requirement in the Energy Policy Act of 2005 that load-serving entities be provided transmission rights to meet their service obligations.

- APPLICABILITY. The Commission reaffirms its decision in Order No. 888 to exercise jurisdiction over unbundled wholesale transmission service, but not the transmission component of bundled retail rates.

- RECIPROCITY. The NOPR would maintain the Commission’s current approach to reciprocity for nonjurisdictional transmission owners.

Comments on the NOPR are due 60 days after publication in the Federal Register.

R-06-30

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Preventing Undue Discrimination and Preference in Transmission Service

Notice of Proposed Rulemaking (NOPR) FERC Docket Nos. RM05-25-000 and RM05-17-000

May 18, 2006

The Commission proposes amendments to its regulations and to the pro forma open access transmission tariff (pro forma OATT), adopted in Order Nos. 888 and 889, to address deficiencies in the pro forma OATT that have become apparent since the issuance of Order Nos. 888 and 889.

The Purpose of the Proposed Rule o To strengthen the pro forma OATT to ensure that it achieves its original purpose

of remedying undue discrimination. o To provide greater specificity in the pro forma OATT to reduce opportunities for

the exercise of undue discrimination, make undue discrimination easier to detect, and facilitate the Commission’s enforcement.

o To increase transparency in the rules applicable to planning and use of the transmission system.

Brief Overview

o Major proposed reforms: o Greater consistency and transparency in ATC calculation o Open, coordinated and transparent planning o Reform of energy imbalance penalties o Reform of rollover rights policy o Clarify tariff ambiguities o Increase transparency and customer access to information

o Core elements of Order No. 888 being retained:

o Comparability requirement o Protection of native load o States jurisdiction over bundled retail load o Functional unbundling to address undue discrimination o Reciprocity

The Applicability of the Proposed Rule

o The proposed rule applies to all public utility transmission providers, including RTOs and ISOs.

o As with Order No. 888, a public utility may propose terms and conditions of open access service that are consistent with or superior to the pro forma OATT.

o The purpose of the proposed rule is not to redesign approved, fully-functional RTO or ISO markets. The Commission does not expect that substantial changes to

Attachment B (Agenda Item 3f)

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those markets would be required as a result of this NOPR.

Significant Proposed Reforms Available Transfer Capability (ATC)

ATC is the transfer capability remaining on a transmission provider’s transmission system that is available for further commercial activity over and above already committed uses. Transmission providers currently calculate the ATC for their systems using different assumptions and methodologies. After concluding that the absence of a consistent ATC methodology increases the discretion of transmission providers and the opportunities for undue discrimination in application of the pro forma OATT, the Commission proposes:

o To ensure consistency in the ATC calculation components, data inputs and modeling assumptions as well as consistency in the exchange of data between transmission providers

o To order public utilities, working through the North American Electric Reliability Council (NERC) and the North American Energy Standards Board (NAESB), to develop appropriate standards within 6 months of the final rule

o To increase the transparency of ATC calculations through the inclusion in each transmission provider’s OATT of its specific ATC calculation methodology, and through posting of relevant data and models on each transmission provider’s open access same-time information system (OASIS)

o To order transmission providers to post on OASIS metrics relating to transmission requests that are approved and rejected

Coordinated, Open and Transparent Transmission Planning The Nation has experienced a decline in transmission investment relevant to load growth since Order No. 888 was issued, which has increased congestion and reduced access by customers to alternative sources of energy. The Commission concludes that transmission providers have a disincentive to remedy transmission congestion on a nondiscriminatory basis and that the current pro forma OATT does not adequately address these problems. Therefore, the NOPR proposes to require that:

o Transmission providers participate in a coordinated, open and transparent planning process

o Each transmission provider’s planning process meet the Commission’s eight planning principles, which are set forth in the NOPR and include coordination (regular meetings), openness, transparency, information exchange (including review of draft plans), comparability (plan must meet service requests and treat customers comparably), dispute resolution, regional coordination, and congestion studies (each transmission provider must prepare studies annually)

o Each transmission provider must describe its planning process in its tariff.

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o The Commission will allow regional differences in planning processes Transmission Pricing

o Pricing of Imbalances – The Commission proposes to reform the pricing of imbalances (i.e., energy and generator imbalances) to ensure that it is related to the cost of correcting the imbalance, to encourage efficient scheduling behavior, and to account for the special circumstances presented by intermittent generators, such as by waiving the higher ends of the imbalance penalties.

o Credits for customer-owned transmission facilities – With respect to credits available to customers that own network transmission facilities that are integrated with the transmission provider’s facilities, the NOPR proposes to clarify that the transmission provider, in designing its rates for OATT service, must treat its own facilities on a comparable basis, and proposes to eliminate the requirement that new facilities can receive credits only if they are "jointly planned" because this requirement may provide a disincentive to coordinated planning.

o Capacity reassignment – For capacity reassignments by transmission customers, the NOPR proposes to eliminate the price cap (which currently is the higher of the original rate, the maximum tariff rate or the customer’s opportunity cost capped at the cost of expansion) and allow negotiated rates between the customer and its assignee, but not for capacity reassigned by the transmission provider or its affiliates.

Non-Rate Terms and Conditions

o Redispatch obligation – The Commission proposes to clarify that when a transmission provider determines that its system lacks capacity to fulfill a request for point-to-point service, a transmission provider must use all of its available redispatch options to satisfy a request for firm point-to-point service and, at the transmission customer's option, these redispatch options must be studied before the customer is obligated to incur the costs and time delays associated with a study of system-expansion options. The Commission also seeks comment on whether, alternatively, it should modify the nature of point-to-point service to require that transmission providers offer a "conditional firm" service that would be subject to curtailment prior to firm service only a limited number of hours of the year.

o Rollover rights (right of first refusal) – The Commission proposes to revise the rollover provision in the pro forma OATT, which grants an ongoing right to transmission customers to renew or “rollover” their contracts, to apply to contracts that have a minimum term of five years, rather than the current minimum term of one year. The NOPR proposes that a customer must exercise its right of first refusal to renew the contract no less than one year prior to the expiration date of the transmission service agreement, rather than within the current 60-day period.

o Hourly firm point-to-point service – The Commission proposes to require transmission providers to offer hourly firm point-to-point service under the pro forma OATT.

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o Designated network resources – The NOPR makes a number of clarifications related to the types of agreements that may be designated as network resources, the process for verifying whether agreements meet the requirements in the pro forma OATT, and the requirement for transmission providers to designate and undesignate network resources on OASIS.

o Reservation priority – The Commission proposes to change the reservation priority rules to give priority to pre-confirmed transmission service requests submitted in the same time period as non-confirmed requests.

Examples of Proposed Increases in Transparency

o In addition to the increased transparency included in the ATC and planning reforms described above, the Commission proposes to require transmission providers to post on OASIS all business rules, practices and standards that relate to transmission services provided under the pro forma OATT, and to include credit review procedures in their OATTs.

o The Commission proposes to require transmission providers and their network customers to use the transmission provider’s OASIS to request designation of a new network resource and to terminate the designation of an existing network resource.

Proposed Reforms to Facilitate Enforcement of the Pro Forma OATT:

o The Commission proposes a number of posting and reporting requirements that will provide the Commission and market participants with information about each transmission provider’s performance of pro forma OATT obligations. For example, the Commission proposes to require transmission providers to post specific performance metrics related to their completion of studies required to evaluate certain transmission requests under the pro forma OATT.

(Name of Transmission Provider) Open Access Transmission Tariff Original Sheet No. 135

ATTACHMENT C

Methodology To Assess Available Transmission CapacityTransfer Capability

To be filed by the Transmission ProviderThe Transmission Provider must include, at a minimum, the following information concerning its ATC calculation methodology: (1) the specific mathematical algorithm used to calculate firm and non-firm ATC (and AFC, if applicable) for its scheduling horizon (same day and real-time), operating horizon (day ahead and pre-schedule) and planning horizon (beyond the operating horizon); (2) a process flow diagram that illustrates the various steps through which ATC/AFC is calculated; and (3) a detailed explanation of how each of the ATC components is calculated for both the operating and planning horizons. (a) For TTC, a Transmission Provider shall: (i) explain its definition of TTC; (ii) explain its TTC calculation methodology (e.g., load flow, short circuit, stability, transfer studies); (iii) list the databases used in its TTC assessments; and (iv) explain the assumptions used in its TTC assessments regarding load levels, generation dispatch, and modeling of planned and contingency outages. (b) For ETC, a transmission provider shall explain: (i) its definition of ETC; (ii) the calculation methodology used to determine the transmission capacity to be set aside for native load, network load, and non-OATT customers (including, if applicable, an explanation of assumptions on the selection of generators that are modeled in service); (iii) how point-to-point transmission service requests are incorporated; (iv) how rollover rights are accounted for; and (v) its processes for ensuring that non-firm capacity is released properly (e.g., when real time schedules replace the associated transmission service requests in its real-time calculations). (c) If a Transmission Provider uses an AFC methodology to calculate ATC, it shall explain: (i) its definition of AFC; (ii) its AFC calculation methodology (e.g., load flow, short circuit, stability, transfer studies); (iii) its process for converting AFC into ATC; (iv) what databases are used in its AFC assessments; (v) the assumptions used in its AFC assessments; and (vi) the reliability criteria used for contingency outages simulation. (d) For TRM, a Transmission Provider shall explain: (i) its definition of TRM; (ii) its TRM calculation methodology (e.g., its assumptions on load forecast errors, forecast

Attachment C (Agenda Item 3f)

(Name of Transmission Provider) Open Access Transmission Tariff Original Sheet No. 136

errors in system topology or distribution factors and loop flow sources); (iii) the databases used in its TRM assessments; (iv) the conditions under which the transmission provider uses TRM; and (v) the process used to prevent double-counting of contingency outages used in its TTC and TRM calculations. A Transmission Provider that does not reserve TRM must so state. (e) For CBM, the Transmission Provider shall state include a specific and self-contained narrative explanation of its CBM practice, including: (i) who performs the assessment (transmission or merchant staff); (ii) the methodology used to perform generation reliability assessments (e.g., probabilistic or deterministic); (iii) whether the assessment method reflects a specific regional practice; (iv) the assumptions used in those assessments; and (v) the basis for the selection of paths on which CBM is set aside. (f) In addition, for CBM, a Transmission Provider shall: (i) explain its definition of CBM; (ii) list the databases used in its CBM calculations; and (iii) prove that there is no double-counting of contingency outages when performing CBM, TTC, and TRM calculations. (g) The Transmission Provider shall post its procedures for allowing CBM during emergencies (with an explanation of what constitutes an emergency, the entities that are permitted to use CBM during emergencies and the procedures which must be followed by the transmission providers’ merchant function and other load-serving entities when they need to access CBM). If the Transmission Provider’s practice is not to reserve CBM, it shall so state.


Reliability Assessment Subcommittee Kevin Dasso, chairman of the Reliability Assessment Subcommittee (RAS), will lead the discussion on the following items: A. Review Status of the 2006 Long-Term Reliability Assessment Report. The RAS will provide an update on the status of the 2006 Long-Term Reliability Assessment report, scheduled to be published September 1, 2006. A request for information necessary to compile the report was issued to the regional managers on January 24, 2006, with due dates of April 3, 2006 and May 19, 2006 for the data and regional narratives, respectively. Action Required: None. B. Overview of the 2006 Summer Reliability Assessment Report The RAS completed work and posted the 2006 Summer Reliability Assessment report on May 15, 2006. NERC expects tighter electricity supplies this summer than last year across much of North America, especially in southern California and southwestern Connecticut. Extreme weather continues to present a significant reliability risk in those areas with lower margins. Coal deliveries from Powder River Basin are increasing, but not enough to restore coal inventories to pre-curtailment levels. Coal delivery limitations do not appear to present a reliability problem for this summer. However, some utilities will need to purchase electricity or use alternate fuels to conserve their coal supplies to ensure that the coal generating units will be available at peak. If coal delivery problems worsen, the ability of some entities to continue to meet electricity demand might be reduced. NERC has placed the three areas noted above on its watch list. During preparation of the report the RAS also completed an in-depth review of the Ontario area of NPCC. The Independent Electricity System Operator is in the process of implementing a day-ahead commitment process and has also added 632 MW of generating capacity. Transmission capability into the Greater Toronto area has been improved. Action Required: None

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C. Status of Regional Interviews As described at prior Planning Committee meetings, the subcommittee is nearing the end of regional interviews intended to delve into the procedures and methodologies used to develop the regional self-assessments. The RAS plans to complete all regional interviews in this cycle by the end of 2006. The subcommittee has been inviting regional representative(s) to describe in depth the processes used to develop their respective regional self-assessments. To date, the subcommittee has conducted interviews with SPP, WECC/NWPP, ECAR, MAAC, NPCC, ERCOT, FRCC, and SERC. The subcommittee plans to interview MRO at its October 10–11 meeting in Chicago, and is working to schedule an interview with ReliabiltyFirst. Action Required: None The next RAS meeting is scheduled for June 20–21, 2006 in Arlington, Virginia.


Load Forecasting Working Group The Load Forecasting Working Group (LFWG) reports to the Reliability Assessment Subcommittee (RAS). Kevin Dasso, chairman of the RAS, will lead the discussion on the following item: Review Status of the LFWG Forecast Bandwidths Used in the Reliability Reports The LFWG is currently preparing to provide forecast bandwidths for the upcoming Long-Term Reliability Assessment. As agreed to at the March 2006 meeting of the Planning Committee, LFWG will provide bandwidths for all current regions. This is not an issue for most regions; however, for ReliabilityFirst and MRO, LFWG will need to use an alternate method to develop reasonable bandwidths (which will carry appropriate caveats). The LFWG was unable to fulfill a request to provide seasonal forecast bandwidths for the 2006 Summer Assessment, as there was neither enough lead time nor sufficient data for the LFWG to meet the required timeline. LFWG is committed to providing the necessary information for future seasonal assessments, but will need guidance with regard to what specific data are available and the timeline for production and delivery. Action Required: Provide the LFWG and RAS with guidance on which data should be made

available (and by when) to produce bandwidths for the reliability assessments and approve its use in the long-term and seasonal assessments.

The LFWG’s next meeting is tentatively scheduled for August 10–11, 2006 in Québec City.


Data Review Task Force The Data Review Task Force reviewed NERC’s electricity reliability organization (ERO) proposed use of net energy for load (NEL) by load serving entity (LSE) as a funding parameter. As a result of the review and relevant discussions on this topic, the task force sent a document to NERC staff to offer insights into the challenges regarding NEL data collection, consistency, and validation. The document focused the discussions on NEL “accounting” challenges at the LSE level. DRTF pointed out the following items for consideration: (1) balancing authorities are the source and level of much of the currently collected NEL data, so an exclusive LSE-level collection would be a somewhat novel approach; (2) “behind-the-meter” generation is not typically part of the current process but may play some part in the new collection; (3) transmission losses are captured by default for balancing authorities but may not be consistently captured or easily validated at the LSE level; and (4) the “small” entity exemption may create some ongoing maintenance. Action Required: None Paul Johnson DRTF Chairman May 19, 2006

Agenda Item 4d PC Meeting June 7–8, 2006

Data Coordination Working Group The Data Coordination Working Group (DCWG) collected and is now checking and correcting the data required for the Long-Term Reliability Assessment (LTRA). The group used the new NERC Reliability Assessment Demand & Capacity form, written by the Data Review Task Force (DRTF), to report aggregate capacity and demand to NERC. DCWG also submitted data to NERC for the Energy Information Administration’s (EIA) EIA-411 Coordinated Bulk Power Supply Program Report, the Reliability Assessment Subcommittee’s (RAS) fuel-type breakdown form (slightly revised this year by the DRTF), and the RAS transmission mileage form. After data are finalized, DCWG and NERC staff will distribute the data to the appropriate parties. DCWG will deliver demand and energy data (one year of actuals and ten years of forecast) to the Load Forecasting Working Group (LFWG) for the LFWG bandwidth work. NERC staff will create tables and graphs for use in NERC’s 2006 LTRA. The EIA-411 data that are not needed for the LTRA will be processed and sent to EIA by July 15, 2006. Action Required: None Kenneth B Keels, Jr DCWG Chairman May 2006

Agenda Item 4e PC Meeting June 7–8, 2006

Data Collection Issues The Reliability Assessment Subcommittee (RAS) is increasingly challenged to obtain all of the data and information at a level of detail it needs to fully analyze reliability and adequacy of bulk power systems. The principal reason for this is the confidentiality and commercial sensitivity placed on certain information as a result of the competitive industry environment. In general, resistance occurs where data or information is needed on a unit-specific basis.

A prime example of this is coal delivery and coal stockpile information. When the Powder River Basin coal delivery issue arose after last year’s train derailment, RAS attempted to get specific information that it could use to evaluate the severity of the problem and its impact on resource adequacy. Because the impacts of the coal delivery slowdown and reduced stockpiles had significant economic implications, generators were reluctant to provide specific information to RAS.

The Planning Committee will discuss possible solutions to data collection issues that will help the RAS and NERC’s Reliability Assessment and Performance Analysis Program obtain the data needed to thoroughly assess and report on bulk power system reliability and adequacy. Action Required: Discuss

Agenda Item 4f PC Meeting June 7–8, 2006

Events Analysis Activities Robert W. Cummings, NERC Director of Events Analysis and Information Exchange, will present an overview of that new program area, highlighting event currently under investigation, and the new NERC Alerts system for sharing lessons learned from disturbances. Action Required: None


Standards Evaluation Subcommittee William O. Bojorquez, chairman of the Standards Evaluation Subcommittee (SES), will lead the discussion on the following: Current Standards Activity The Planning Committee will receive a summary update report on the status of NERC standards that are currently under development. Action Required: None


FERC Assessment of NERC Standards On May 25, Don Benjamin distributed background material for the Planning Committee’s (PC) and Operating Committee’s (OC) discussion of the FERC Staff Preliminary Assessment of NERC Standards (Attachment A). This document covers 12 major issues in the Assessment, and includes thoughts from Dave Nevius and Don Benjamin on each of those issues. Scott Helyer, PC chairman, also wrote to the PC subcommittee chairs on May 25 enlisting their help in reviewing the FERC staff assessment and providing the PC with that input prior to, or at, the June 7–8 meeting. Action Required: Discuss

Planning Committee and Operating Committee Discussion of the FERC Staff Preliminary Assessment of Proposed Mandatory Reliability Standards

Background On May 11, 2006, the Federal Energy Regulatory Commission (FERC) issued a Staff Preliminary Assessment of the North American Electric Reliability Council’s Proposed Mandatory Reliability Standards. The Commission anticipates issuing a Notice of Proposed Rulemaking (NOPR) on the reliability standards in July. The Commission directed NERC to submit its response to the staff preliminary assessment report by June 26, 2006, and also invited others to comment. The Commission intends to hold a technical conference on the proposed standards and the staff’s preliminary assessment—the date has not yet been announced.

The Commission staff began studying the existing reliability standards in the fall of 2005, soon after enactment of the Energy Policy Act of 2005. In transitioning from voluntary standards to mandatory standards with financial penalties, the Commission needs to ensure that NERC’s proposed standards meet the statutory requirements for enforcement. According to section 215 of the Federal Power Act (FPA), which was created as a result of the Energy Policy Act of 2005, “the Commission may approve, by rule or order, a proposed reliability standard or modification to a reliability standard if it determines that the standard is just, reasonable, not unduly discriminatory or preferential, and in the public interest.” The preliminary staff assessment is one input that Commission will use in determining whether to approve the proposed standards, in addition to inputs from NERC, industry stakeholders, and the public.

On April 4, 2006, NERC filed its application for certification as the electric reliability organization (ERO) in accordance with FPA section 215 and the Commission’s Order No. 672 (issued on February 3, 2006). NERC simultaneously submitted a petition requesting Commission approval of 102 proposed reliability standards. In its petition, NERC identified a number of areas for improvement of the standards and proposed a work plan to address these issues. The staff’s preliminary assessment acknowledges these issues identified by NERC and notes some additional areas of concern. The staff’s overarching concerns are summarized as follows:

• Blackout Report Recommendations: Although the U.S/Canada Power System Outage Task Force blackout report identified many of the primary causes of the August 2003 blackout and other major blackouts in North America, some of the recommendations are not yet addressed in the reliability standards.

• Ambiguity: Elements of some standards appear to be subject to multiple interpretations, especially with regard to the specificity of the standards’ requirements, measurability, and degrees of compliance. This ambiguity also extends to the differing definitions for the Bulk-Power System and the Bulk Electric System.

• Technical Adequacy: The requirements specified in some standards may not be sufficient to ensure an adequate level of reliability. While Order No. 672 notes that “best practice” may be an inappropriately high standard, it also warns that a “lowest common denominator” approach will not be acceptable if it is not sufficient to ensure system reliability. NERC’s petition acknowledges that considerable effort is needed to bring the standards to the anticipated level of excellence and commits to working toward that goal.

For discussion at PC and OC Meetings, June 7-8, 2006

Attachment A (Agenda Item 5b)


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• Measures and Compliance: These two components are absent in some of the standards, which could lead to inconsistent interpretation and enforcement of the standards. NERC’s petition identifies 21 standards in this category and states that a project is underway to file the measures and compliance elements by November 2006.

• Fill-in-the-Blank Standards: "Fill-in-the-blank standards" refer to those standards for which Version 0 does not contain a specific requirement that is enforceable against users, owners and operators of the grid, but rather provides only broad direction to the Regional Reliability Organizations (RROs) to adopt a particular procedure or criteria for these entities to follow. These standards raise concerns in two respects (i) they are not enforceable against users, owners and operators of the grid, but rather only provide broad direction to RROs, and (ii) the more specific implementing standards adopted by the RROs have not undergone an approval process under section 215 and hence cannot themselves be enforced by the Commission or ERO. Beyond the near-term enforceability problems associated with these types of standards, the Commission staff has concerns that the “blanks” be populated in ways that generate unnecessary regional differences. NERC’s petition acknowledges there are issues with fill-in-the-blank standards and proposes both short-term and long-term solutions.

• Applicability: FPA section 215 requires that “all users, owners, and operators” comply with mandatory reliability standards approved by the Commission. The current standards do not define or list the “users, owners, and operators” that are required to follow the standard. The applicability of each standard needs to be clear.

Request for Inputs from NERC Operating and Planning Committees The FERC staff’s preliminary assessment of the reliability standards is 137 pages in length and addresses both overarching issues and detailed comments on individual standards. We encourage the NERC technical committees to review the report in its entirety and work within their individual organizations to provide appropriate inputs to the Commission by June 26.

To focus technical committee inputs to the FERC staff preliminary assessment of the standards, NERC staff has identified 12 key issues for discussion. The first four issues are addressed to both committees; the next five are addressed to the OC and the last three are addressed to the PC. The issues are:

1. Definition of bulk electric system (OC and PC)

2. Vegetation management (OC and PC)

3. Reactive and voltage control and reactive reserves (OC and PC)

4. Under-voltage load shedding (OC and PC)

5. Determination of transfer capabilities (OC and PC)

6. Contingency reserves (OC)

7. 30-minute recovery from IROL violation (OC)

8. Use of TLR to address SOL and IROL violation (OC)

9. Training (OC)

10. Backup control centers (OC)

11. Transmission performance (planning) criteria (PC)


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12. Determination of facility ratings (PC)

The Operating and Planning Committees will discuss these issues at their June 7-8, 2006 meetings, and provide written comments and notes from those discussions to NERC’s Director of Standards no later than June 14, 2006. Selected excerpts from the FERC staff report and a set of discussion questions are provided below for each issue.

How to Read this Document This background paper covers 12 issues. Each issue begins with a section titled “FERC Staff Comments,” which includes excerpts from the FERC staff assessment. Then we list five generic “Discussion Questions” for that topic for which we are seeking answers from the OC or PC or both. The third section is “Thoughts from the PC and OC Secretaries” that Dave Nevius and Don Benjamin included to provide the committees with a starting point for their discussions. These “thoughts” are just that, and are not necessarily NERC’s draft responses to the Commission.


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Issue 1. Definition of Bulk Electric System (OC and PC)

FERC Staff Comments (pp. 25-26) The differences between the definition of Bulk-Power System in section 215 of the FPA and the definition of Bulk Electric System found in the NERC Glossary upon which the NERC standards rely, create a problematic discrepancy that could create reliability gaps. This discrepancy, if left unaddressed, will interfere with maintaining reliability consistently across the Regions and may be inconsistent with Order No. 672. This gap could allow for some interconnected electric energy transmission networks, and electric energy from generating facilities needed to maintain transmission system reliability to be outside of the mandatory Standards.

The NERC Glossary defines the Bulk Electric System as follows:

“As defined by the Regional Reliability Organization, the electrical generation of

resources, transmission lines, interconnections with neighboring systems, and

associated equipment, generally operated at voltages 100 kV or higher. Radial

transmission facilities serving only load with one transmission source are

generally not included in this definition.”

When the task of defining the Bulk Electric System is delegated to each RRO, the result could be conflicting multiple definitions that subject different facilities to, or exclude different facilities from, the requirements of the standards.

Further, section 215(a)(1) defines Bulk-Power System as:

“Facilities and control systems necessary for operating an interconnected electric

energy transmission network (or any portion thereof), and electric energy from

generating facilities needed to maintain transmission system reliability. The

term does not include facilities used in the local distribution of electric energy.”

The FPA and NERC definitions obviously differ. The standards currently are applied only to the Bulk Electric System as defined by each Region. However, section 215(a)(3) of the FPA defines [a] Reliability Standard as a requirement approved by the Commission to provide for reliable operation of the Bulk-Power System. The term Bulk Electric System does not appear to include all the system components from all non-distribution voltage levels, control systems, and electric energy from all generating facilities needed to maintain transmission system reliability included in the definition of Bulk-Power System.

(pp. 110-112) The concern in this chapter is that the discrepancy is magnified when applied to contingencies that must be evaluated as part of the transmission planning process. The current Planning Standards apply to all elements that constitute the Bulk Electric System. According to [the NERC] definition, each RRO may designate the scope of facilities to be included in, or excluded from, the system. Conflicting multiple definitions could result, which would in turn subject different facilities to the requirements of the standards or, alternatively, exclude various facilities from the standards. Therefore, the definitions of Bulk Electric System and Bulk-Power System are very different with respect to the facilities to which the TPL standards would apply. The Bulk Electric System definition may not include all the elements and all the voltage levels implied in the definition of Bulk-Power System.


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Discussion Questions 1. Do you agree or disagree with the assessment outlined above? Explain why.

2. Are their any misperceptions expressed that can be corrected with additional information? Please provide information to address the misperception.

3. Is there ongoing work to address this issue?

4. What additional work should be initiated to address this issue?

5. What additional inputs would you like to provide for the NERC response on this issue?

Thoughts from the PC and OC Secretaries Neither definition is absolute, and the FPA “Bulk-Power System” definition also leaves room for question and interpretation, such as:

1. Which facilities are “necessary for operating an interconnected electric energy transmission network,”

2. What constitutes “any portion thereof,” and

3. Why is “electric energy” considered as a part of the “system.”

NERC’s definition of “Bulk Electric System” provides some guidance on which facilities should be included in NERC’s reliability standards—those operated at voltages of 100 kV or higher and part of the network, and uses the word “generally” because the definition should not set specific limit.

From a practical standpoint, the failure of those parts of the transmission network below 100 kV or transmission lines that serve load (not generation) radially will have little effect on the operations of the Interconnection, and would not likely cause a widespread cascading outage. On the other hand, Transmission Operators or Reliability Coordinators may decide to include certain lower voltage transmission elements in their contingency analyses.


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Issue 2. Vegetation Management (OC and PC)

FERC Staff Comments (p. 18) [S]taff is concerned that, although the industry developed a vegetation management standard to implement Blackout Report Recommendation Number 16, the minimum electrical clearance portion of that standard is sufficiently low that it may not be adequate to maintain reliability or otherwise protect public safety.

(pp. 20-21) The Transmission Vegetation Management standard (FAC-003-1) requires a Transmission Owner to determine and document the minimum allowable clearance between energized conductors and vegetation before the next trimming. It specifically provides that “Transmission Owner-specific minimum clearance distances shall be no less than those set forth in the Institute of Electrical Engineers (IEEE) Standard 516-2003 (Guide for Maintenance Methods on Energized Power Lines). However, IEEE Standard 516-2003 is intended for use as a guide by highly-trained maintenance personnel to carry out live-line work using specialized tools under controlled environments and operating conditions, not for those conditions necessary to safely carry out vegetation management practices.

The allowable clearances in the IEEE standard are significantly lower than those specified by the relevant U.S. safety codes. As such, use of IEEE clearance provision as a basis for minimum clearance prior to the next tree trimming as a Requirement in vegetation management may not be appropriate for safety and reliability reasons. For example, the IEEE Standard 516-2003 specifies a 2.45-foot clearance from a live conductor for the 120 kV voltage class, whereas the ANSI Z-133 standard specifies 12-feet, 4-inches as the approach distance for the 115 kV voltage class.

Staff notes that some transmission owners currently use more stringent requirements and therefore, adopting the IEEE clearance provision for use with regular vegetation maintenance practices could be viewed as a “lowest common denominator” approach, about which the Commission expressed dissatisfaction in Order No. 672. Widespread implementation of this approach could inadvertently subject the public to safety hazards and the potential for multiple tree contacts under non-controlled conditions. In addition, use of the IEEE Standard 516-2003 could create unintended consequences that cause the transmission owners who currently maintain more stringent vegetation management programs based on standards such as the ANSI Z-133 to relax their practices to meet the less-stringent minimum requirement set forth in the NERC vegetation standard, exactly the opposite result intended by EPAct 2005 and FPA section 215. As a result, the danger could exist that increased amounts of vegetation will become vulnerable to tree contact, the initial trigger point of the August 2003 blackout. Staff is not necessarily recommending use of the ANSI Z-133 standard as the minimum standard; however, we seek comment on whether the IEEE standard is sufficient to maintain reliability and protect public safety and, if not, what modifications to that standard should be made or whether an alternative standard is required to satisfy Order No. 672.

(pp. 56-58) [T]he current standard does not designate maximum allowable inspection intervals. Rather, each Transmission Owner is responsible for maintaining a formal transmission vegetation management program that defines a schedule for and the type of right of way vegetation inspections (e.g., aerial, ground). Thus, a Transmission Owner cannot be faulted for the length of its inspection interval, provided that it has defined the schedule in its formal program.


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Thoughts from the PC and OC Secretaries

Inspection Intervals

NERC used the considerable wisdom of the industry, including vegetation management providers, utility vegetation managers, and regulators, to develop FAC-003. The standard recognizes that a successful vegetation management program must consider each line’s operating voltage, fire risk, reasonably anticipated tree and conductor movement, vegetation species types and growth rates, species failure characteristics, local climate and rainfall patterns, line terrain and elevation, location of the vegetation within the span, and worker approach distance requirements. Therefore, if the Transmission Owner properly considers these variables, it should not be faulted for the length of its inspection interval.

1. Considering the wide diversity of climate and terrain in the U.S. and Canada, how would a maximum inspection interval add to the effectiveness of this standard?

2. Would the same interval be used for all types of climate and terrain?

3. What should that interval be?

IEEE Standards for “Clearance 2”

This requirement sets the minimum distance between the transmission conductors and vegetation that must be always be maintained. (See figure at right) In other words, clearance C1 is established when the vegetation is trimmed, and that clearance is not allowed to become less than C2.

NERC selected IEEE Standard 516-2003 as the basis for C2. That standard is already well established in the industry, and has evolved over many years. (IEEE’s ANSI-approved standards development process is very similar to NERC’s.)

The FERC staff assessment suggests the need for considerably more clearance, citing U.S National Safety Code Standard ANSI Z-133 as an example that establishes safe clearances for working near a transmission line. The question therefore becomes whether those clearances are needed to prevent flashovers between a conductor and a tree.

C1 C2C1 C2


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Issue 3. Reactive and Voltage Control and Reserves (OC and PC)

FERC Staff Comments (pp. 118-119) [VAR-001] requires a Transmission Owner to “acquire sufficient reactive resources within its area to protect the voltage levels under normal and Contingency conditions,” and “maintain system and Interconnection voltages within established limits.” These requirements may not assure reliable operation of power systems when operating under conditions that make them vulnerable to voltage collapse. Under heavy system loading conditions, and depending on system characteristics, operating voltages at levels that are traditionally considered normal (e.g., 95 percent nominal) may no longer be stable operating voltages. Voltage magnitudes alone are poor indicators of voltage stability.

The VAR standard does not address these pre- and post-contingency operating voltages, nor does it require Transmission Operators to maintain voltage levels above the voltage collapse points (i.e., voltage instability) with a sufficient margin in accordance with good utility practice. For example, the Western Electric Coordinating Council’s Reliability Criteria document, which contains a standard on voltage support and reactive power, states:

For transfer paths, post-transient voltage stability is required with the path modeled at a minimum of 105% of the path rating (or Operational Transfer Capability) for system normal conditions (Category A) and for single contingencies (Category B). For multiple contingencies (Category C), post-transient voltage stability is required with the path modeled at a minimum of 102.5% of the path rating (or Operational Transfer Capability).

The above criteria state explicitly the voltage stability requirement and the margin requirements between the actual operating limits and the test levels in simulations for different contingencies. Staff notes that margins in Operational Transfer Capability are substitutable for voltage margins and either application is effective in ensuring reliability.

The VAR standard does not contain a Requirement that operations planning studies be carried out to identify the minimum permissible pre-contingency voltage levels and reactive power reserves. Requiring such studies would assure stable post-contingency voltage levels to avoid voltage collapse. These studies would also identify feasible corrective operating actions, which may include load shedding in pre-contingency conditions to avoid voltage collapse that may occur either in the pre- or post-contingency conditions. The standard does not currently require that these corrective operating actions be communicated to system operators as part of the day-ahead operations plan. In addition, the standard does not require similar voltage stability assessments to be carried out periodically during real-time operations so that system operators can continuously respond to changing system conditions.

The current standard does not address Recommendation Number 23 of the Blackout Report, which is to “[s]trengthen reactive power and voltage control practices in all NERC regions.” Staff notes that NERC, in response to this recommendation, established the Transmission Issues Subcommittee (TIS), which completed an evaluation of reactive power planning.

(p. 119) Voltage and reactive control is an integral part of Interconnection Reliability Operating Limits (IROLs). Voltage collapse can result in a widespread cascading outage on an Interconnection. Therefore, reliable operations of the Bulk-Power System require that Reliability Coordinators be authorized to direct and coordinate voltage and reactive control


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among operating entities in an Interconnection and assure that they can fulfill their role as the entity with the “highest level of authority.”

(p. 120) Staff notes that [VAR-001-0] Requirement R3, which requires that “[e]ach Purchasing-Selling Entity shall arrange for (self-provide or purchase) reactive resources to satisfy its reactive requirements identified by its Transmission Service Provider,” is not currently applicable to Load-Serving Entities who are responsible for significantly more load on the system than the Purchasing-Selling Entities. The applicability of the standard is currently limited to Transmission Operators, Generator Operators and Purchasing-Selling Entities. This standard does not apply to Reliability Coordinators and Load-Serving Entities.






Thoughts from the PC and OC Secretaries As the FERC staff assessment points out, the NERC Planning Committee published its report on “Evaluation of Reactive Power Planning and Voltage Control Practices in Response to NERC Blackout Recommendation 7a,” (see text box at right) which identified a number of observations and considerations for possible inclusion into future NERC Reliability Standards, and several notable (best) practices for information purposes to complement the NERC standards.

NERC Recommendation 7a

“The Planning Committee shall reevaluate within one year the effectiveness of the existing reactive power and voltage control standards and how they are being implemented in practice in the ten NERC regions. Based on this evaluation, the Planning Committee shall recommend revisions to standards or process improvements to ensure voltage control and stability issues are adequately addressed.”


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Issue 4. Under-voltage Load Shedding (OC and PC)

FERC Staff Comments (pp. 48-49) Shedding of firm load is an operating measure of last resort to contain system emergencies and prevent cascading. The system operators must have the capability to manually or automatically shed load in a timely manner to return the system to a stable condition. The Blackout Report states that

The investigation team concluded that since the Sammis-Star 345 kV outage was the critical event leading to widespread cascading in Ohio and beyond, if manual or automatic load-shedding of 1,500 MW had occurred within the Cleveland-Akron area before that outage, the blackout could have been averted.

However, it should be noted that at that time there were no automatic or quick-acting manual load shedding capabilities in the area. While these [EOP] standards require Transmission Operators and Balancing Authorities to have the capability to shed load in a timeframe adequate for responding to an emergency, they do not specify the minimum capability that must be provided and the maximum allowable delay before load shedding can be implemented.

(p. 49) While the current standards provide operators with the authority to shed load to respond to an emergency and return the system to a stable state, the operators may hesitate to initiate such actions in appropriate circumstances without assurances that they will not be subject to liability or retaliation, even if their action is in accordance with previously approved guidelines. Recognizing the importance of this issue, the Blackout Report Recommendation Number 8 recommends that operators who initiate load shedding pursuant to approved guidelines should be shielded from liability or retaliation. The current standards do not require that these safeguards be provided to shield operators from retaliation when they declare an emergency or shed load. Staff notes that NERC readiness audits seek confirmation that such protection is provided to the operators by their employers. Staff believes this is a positive step, but not a substitute for addressing this issue in the standards.

(pp. 51-52) [EOP-003-0] requires that, after taking all other remedial steps, load be shed rather than risk an uncontrolled failure of components or cascading outages of the Interconnection. However, the standard does not specify the minimum load shedding capability that should be provided and the maximum amount of delay before load shedding can be implemented. This issue was explained in greater detail in the Primary Issues section above.

The standard does not require periodic drills of simulated load shedding (not actual shedding of firm load). Periodic simulated drills are important to test the effectiveness of the processes, communications and protocols, and to familiarize operators from Reliability Coordinators, Transmission Operators and Load Serving Entities with their respective roles and responsibilities associated with the load shedding plans.


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NERC Recommendation 8b

Each regional reliability council shall complete an evaluation of the feasibility and benefits of installing undervoltage load shedding capability in load centers within the region that could become unstable as a result of being deficient in reactive power following credible multiple-contingency events. The regions are to complete the initial studies and report the results to NERC within one year. The regions are requested to promote the installation of undervoltage load shedding capabilities within critical areas, as determined by the studies to be effective in preventing an uncontrolled cascade of the power system.






Thoughts from the PC and OC Secretaries

Undervoltage load shedding

In response to NERC Blackout Recommendation 8b (see text box below), the NERC Planning Committee reviewed each regional reliability council’s evaluation of the feasibility and benefits of installing undervoltage load shedding capability. The result was the committee’s “Review of Regional Evaluations of Undervoltage Load Shedding Capability in Response to NERC Blackout Recommendation 8b.”

The report calls for a number of follow-on recommendations to be completed by the PC and the regions along with an implementation plan. In general, the recommendations address the following areas:

• Development of UVLS study guidelines;

• Development of regional UVLS implementation plans;

• Survey of existing UVLS systems installed on the bulk electric system; and

• Status of the development of methods for more accurately determining and modeling load characteristics.

As part of its ongoing activities in the UVLS, voltage control, and reactive power areas, the PC will:

• Review, monitor, and implement the report recommendations, and

• Work with regional groups and others to develop proposed UVLS standard authorization requests to incorporate, as appropriate, into the NERC reliability standards the lessons learned from this report and the implementation of the follow-on recommendations.

Regarding the FERC staff’s findings that “the PRC standards are not specific enough to be interpreted as requiring an integrated and coordinated approach to achieving the above goals and principles,” NERC suggests that we first determine the functional requirements for effective under-voltage load shedding applications that achieve the objectives of NERC Recommendation 8b, and in the process of doing that, will expect that our standards will


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include the necessary coordination between Planning Authorities and Transmission Planners.

Shielding from liability or retaliation

The FERC staff also suggests that operators who initiate load shedding pursuant to approved guidelines should be shielded from liability or retaliation as specified in the U.S.-Canada Power Outage Task Force Blackout Report Recommendation 8. That’s a very important point; however, the Blackout report’s recommendation is aimed at “Legislative bodies and regulators…” and we question whether it would be appropriate for NERC standards to address issues of legal protection.

Minimum and maximum load shedding times

NERC Emergency Operations Standards (EOP) explain that Reliability Coordinators must direct that action occur within 30 minutes:

IRO-001-0 — Reliability Coordination — Responsibilities and Authorities. R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling 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.

Furthermore, other NERC standards that cover recovery from Interconnection Reliability Operating Limit violations require operator action “as soon as possible” but no longer than 30 minutes.

1. To what degree should NERC standards specify 1.) the amount of load shedding capability that must be available to the Transmission Operator, and 2.) how quickly the Transmission Operator should be able to shed that load.

2. To what degree should NERC standards specify the maximum time to shed load?


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Issue 5. Determination of Transfer Capabilities (OC and PC)

FERC Staff Comments (p. 61) Staff notes that entities in different regions have historically calculated transfer capabilities using different assumptions or approaches. These approaches may be different between the Reliability Coordinators and Planning Authorities in a region, and may also vary from region to region. Therefore, the variable application of transfer capabilities is essentially a regional difference. A move toward standardization of the inter-regional and intra-regional transfer capability may be desirable to ensure an adequate level of reliability and minimize undue negative impact on competition.

(p. 76) The standards leave the development of methodologies and the procedures for periodic review of TTC, ATC, CBM and TRM calculations to RROs. This has resulted in different interpretations and applications of calculation methodologies resulting in different values for ATC when using the same data and assumptions. As such, the different approaches could have an undue negative impact on competition. The Commission is considering this issue in Docket Nos. RM05-17-000 and RM05-25-000 and anticipates addressing it in any Notice of Proposed Rulemaking that may be issued in those dockets.

(p. 80) Staff notes that the RROs have historically calculated TTC/ATC using different approaches.

(p. 80) The standard does not specify how CBM is determined and allocated across transmission paths. Further, the standard does not address the effect of associated transmission service requirements and curtailment provisions on transmission customers.

The standard does not specify the criteria to be used in determining the inclusion or exclusion of generation resources, reserves and loads described in four of its Requirements (R1.5, R1.6, R1.9 and R1.10).

(p. 81) [MOD-005-0] does not, however, actually require there to be a consistent and uniform calculation of CBM. This standard has been referred to as a “fill-in-the-blank” standard.

(p. 81) [MOD-006-0] requires each Transmission Service Provider to document its procedure on the use of Capacity Benefit Margin values, but not to implement a consistent and uniform calculation of CBM.

(p. 81) [MOD-007-0] does not specify how CBM should be reserved to allow both Transmission Providers and Transmission Customers to meet their respective generation reliability criteria.






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Thoughts from the PC and OC Secretaries The FERC staff’s concerns are linked to two characteristics of NERC’s standards: 1.) the “fill-in-the blank” standards that refer to unspecified regional standards, and 2.) the regional standards themselves that may or may not be coordinated between the regions. NERC is addressing both of these topics

Part of NERC’s reorganization to become the Electric Reliability Organization is the expansion of its Standards Program to include the coordination and incorporation of regional standards into the set of ERO standards. NERC has created a new position on its staff within its Standards Program to perform this function to work with the regions to help coordinate their standards. This is especially important for those standards that address transfer capability between regions.

ATC Calculations

Regarding ATC calculations, NERC and NAESB recently agreed to an improved process for coordinating reliability standards with complementary business practices, and formed a joint working group to develop ATC standards and practices. We expect this closer coordination between NERC and NAESB to more effectively aggregate the experts from the engineering, planning, operations, and marketing communities of the industry.

Reliability standards are based on the laws of physics that we cannot change plus judgements of risks and economics—including those of the marketplace—that are subjective. We know from experience that transmission use brings a host of issues to the table that stem from the conflicts between the physics of actual power flow paths versus the contract path provisions of transmission tariffs.

NERC encourages the FERC staff (as well as state and provincial regulatory authorities) to help NERC and NAESB develop the ATC reliability standards and business practices that help the Reliability Coordinators and Transmission Operators protect the reliability of the bulk electric system first and foremost, and provide value to the marketplace.


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Issue 6. Contingency Reserves (OC)

FERC Staff Comments (p. 27) Contingency reserves are needed to compensate for the loss of generation resources so that the system frequency can be returned to 60 Hz. Specific Requirements concerning the composition of the reserves and the restoration time are left to Regions and sub-Regions to determine. For example, the following determinations are all left to individual Regions, sub-Regions, and Reserve Sharing Groups to make: the minimum reserve Requirement, the permissible mix of spinning and non-spinning operating reserve that may be included in Contingency Reserve, the procedure for applying Contingency Reserve in practice, any limitations on the amount of interruptible load, and what is counted toward spinning reserve. No specificity is provided concerning how these requirements are to be determined.

(p. 30) Requirement R3.1 [in Standard BAL-002-0] requires that a Balancing Authority or Reserve Sharing Group carry at least enough contingency reserves to cover the most severe single contingency. One interpretation of this requirement is that the most severe contingency is limited only to generation loss. However, a second, more stringent interpretation is that it can be applied to loss of supply which was the result of a transmission or generation contingency.

Further, the minimum percentage of spinning reserve required as part of the contingency reserve is not defined in the standard but is at the discretion of each RRO. Not having a minimum requirement could result in an entity “leaning on the system,” which would result in an undue negative impact on competition.

Various regions have different definitions as to which resources are eligible to be counted as spinning reserves. For example, in some regions large irrigation pumping and pumped hydro resources are permitted to be used as spinning reserves, and in other regions they are not. There should be a sound technical basis for any such difference.

The standard states that a lower reporting threshold for the size of the minimum disturbance may be required by the RROs. To be enforceable, these lower reporting thresholds, along with their rationale, should be documented in the Regional Differences section.







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Thoughts from the PC and OC Secretaries There are at least four issues to consider:

1. Performance expectations. NERC’s Disturbance Control Standard in BAL-002 establishes the performance NERC expects of a Balancing Authority or collection of Balancing Authorities that form a reserve sharing group. Excerpts follow:

BAL-002-0 — Disturbance Control Performance. R4. A Balancing Authority or Reserve Sharing Group shall meet the Disturbance Recovery Criterion within the Disturbance Recovery Period for 100% of Reportable Disturbances. The Disturbance Recovery Criterion is:

R4.1. A Balancing Authority shall return its ACE to zero if its ACE just prior to the Reportable Disturbance was positive or equal to zero. For negative initial ACE values just prior to the Disturbance, the Balancing Authority shall return ACE to its pre- Disturbance value.

R4.2. The default Disturbance Recovery Period is 15 minutes after the start of a Reportable Disturbance. This period may be adjusted to better suit the needs of an Interconnection based on analysis approved by the NERC Operating Committee.

Therefore, if a Balancing Authority or collection of Balancing Authorities that comprise a reserve sharing group achieve this performance, they are not “unduly” leaning on the Interconnection from a reliability perspective. In other words, NERC standards recognize that perfect control is not possible, and those standards establish what the industry has agreed is an acceptable degree of “leaning.” It is not clear when leaning has an undue impact on competition.

2. Definition of a Reportable Disturbance listed in NERC’s glossary.

Reportable Disturbance. Any event that causes an ACE change greater than or equal to 80% of a Balancing Authority’s or Reserve Sharing Group’s most severe contingency.

The standard depends on this definition, and is therefore open to how the reserve sharing group determines its “most severe contingency.” NOTE: This is a “fill-in-the blank” standard that the Operating Committee should address.

3. The degree to which the NERC standard should specify the composition of contingency reserves, and the time limits for re-establishing those reserves. BAL-002 specifies that “The default Contingency Reserve Restoration Period is 90 minutes. This period may be adjusted to better suit the reliability targets of the Interconnection based on analysis approved by the NERC Operating Committee.”

4. Ancillary services and standards for generators. At what point do the specifications for contingency reserves belong in NERC standards versus ancillary service schedules, or in the definitions of Interconnected Operations Services? Does NERC need standards for generator owners or operators that would specify the attributes of contingency reserves?

New


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Issue 7. 30-Minute Recovery from IROL Violation (OC)

FERC Staff Comments (p. 19) The Interconnection Reliability Operations and Coordination (IRO) standards are a good example of the potential for multiple interpretations and the resulting impact on the reliability of the interconnected grid. Standard IRO-005-0 states:

If a potential or actual IROL violation cannot be avoided through proactive intervention, the Reliability Coordinator shall initiate actions or emergency procedures to relieve the violation without delay, and no longer than 30 minutes.

(p. 68) One interpretation of this Requirement allows an Interconnection Reliability Operating Limit (IROL) to be exceeded during normal operation (prior to a contingency), provided that corrective actions are taken within 30 minutes. In this interpretation, if a single critical contingency were to occur, it would result in instability, uncontrolled separation or perhaps cascading outages. A more conservative interpretation of this Requirement is that an IROL should only be exceeded after a contingency and the system must subsequently be returned to a secure condition as soon as possible, but in no longer than 30 minutes. This particular issue of variable interpretation in the IRO standards relating to IROL violations contributing to system instability also affects other standards such as TOP-004-0 and TOP-007-0.

(p. 102) The primary reliability goal of the Transmission Operations standards is to ensure that instability, uncontrolled separation or cascading outages will not occur as a result of the most severe single contingency. However, these [TOP] standards are worded ambiguously enough to be interpreted in two very different ways. A conservative interpretation is that under normal system conditions, i.e., before any contingency occurs, the system must be operated within an IROL. A less strict interpretation of these standards is that operation above IROLs under normal pre-contingency conditions is permitted provided the system is returned to a secure operating state as soon as possible but not later than 30 minutes after the IROLs were exceeded. In the case of the latter interpretation, during the period when IROL is exceeded even a single system contingency (such as the loss of transmission circuit, transformer, generator, or single DC pole) could cause instability, uncontrolled separation, and even a cascading blackout.

(p. 105) [TOP-004-0] requires the operation of the system within IROL and SOL. When the system enters an unknown state (i.e., any state for which operating limits have not been determined), Requirement R4 of Standard TOP-004-0 requires the operator to “restore operations to respect proven reliable power system limits within 30 minutes.” The phrase “within 30 minutes” could be interpreted as a grace period. However, such an interpretation may not be consistent with the intent that while 30 minutes is deemed a reasonable time period, it is expected that actions will be taken as soon as possible and without delay.

(p. 50) The standard requires Transmission Operators and Balancing Authorities to develop, maintain, and implement a set of plans to mitigate operating emergencies resulting from either insufficient generation or transmission. There is no similar requirement for Reliability Coordinators, who are the highest level of authority responsible for the Bulk-Power System.

The standard requires “the [Transmission Operators] to implement load reduction in sufficient amount and time to mitigate IROL violations before system separation or collapse


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would occur. The load reduction plan must be capable of being implemented within 30 minutes.” One interpretation of this requirement is that power transfers must be adjusted within 30 minutes to relieve IROL overloads. Another interpretation is that load reduction - interpreted as load shedding - must be capable of being implemented within 30 minutes after an operating emergency is declared. The latter interpretation could lead to an inappropriate conclusion that load shedding capability with an implementation time of up to 30 minutes is acceptable to deal with system emergencies. This could expose the system to higher risk since load shedding is the option of last resort and must be capable of being implemented in a much shorter time period than 30 minutes.

(p. 71) Other standards require the system to be operated in a manner that allows it to be returned to a stable state as soon as possible but no longer than 30 minutes after a contingency occurs and to be able to withstand another contingency without cascading. However, [IRO-004-0] does not require that the system be assessed in the next-day planning analysis to identify the control actions needed to bring the system back to a stable state, with an effective implementation time of within 30 minutes, so that the system will be able to withstand the next contingency without cascading.

(p. 102) This group of [IRO] standards does not, however, require that the system be assessed to the same extent in the day ahead planning analysis, nor does it require identification of control actions, implementable within 30 minutes, that are needed to bring the system back to a stable state in order to withstand the next contingency without cascading. This may present a potential vulnerability as operators may not be aware of available control actions or worse may not have control actions, other than firm load shedding, available to them to adjust the system to a stable state after it incurs its first contingency. This can lead to poor execution and reliability risk after the first contingency has occurred in real-time operations.






Thoughts from the PC and OC Secretaries Interconnection Reliability Operating Limits are among the most important real-time operating measurements, but IROLs cannot be determined solely by meter readings, or equipment status indicators, or other SCADA information. IROLs are determined by simulating the failure of an element of the bulk electric system1, and then calculating whether the system will, after that failure, quickly stabilize with all generators and transmission lines remaining on line and operating within their safe limits. Those “what if”

1 We often refer to these failures as “maximum credible” events. That is, events that are one would reasonably expect to occur, rather than a collection of unlikely or unrelated failures.


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cases that result in an unstable bulk electric system with uncontrolled, cascading transmission or generator failures, are IROLs.

In other words, an IROL is an operating “state” that system operators must move away from as quickly as possible.

Current NERC reliability standards require the Transmission Operator or Reliability Coordinator to mitigate an IROL violation as soon as possible, but no longer than 30 minutes. Here are a few examples:

TOP-007-0 — Reporting SOL and IROL Violations. R2. Following a Contingency or other event that results in an IROL violation, the Transmission Operator shall return its transmission system to within IROL as soon as possible, but not longer than 30 minutes.

IRO-001-0 — Reliability Coordination — Responsibilities and Authorities. R3. The Reliability Coordinator shall have clear decision-making authority to act and to direct actions to be taken by Transmission Operators, Balancing Authorities, Generator Operators, Transmission Service Providers, Load-Serving Entities, and Purchasing-Selling 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-005-0 — Reliability Coordination — Current Day Operations. R5. Each Reliability Coordinator shall identify the cause of any potential or actual SOL or IROL violations. The Reliability Coordinator shall initiate the control action or emergency procedure to relieve the potential or actual IROL violation without delay, and no longer than 30 minutes. The Reliability Coordinator shall be able to utilize all resources, including load shedding, to address an IROL violation.

The 30-minute limit for mitigating IROL violations is one of many standards gleaned from years (decades) of interconnected systems operation experience, and represents a tradeoff between 1.) the time that allows the Transmission Operator or Reliability Coordinator to mitigate the violation without having to shed load or disconnect transmission system components (neither of which is desirable), and 2.) the risk that some event will occur before the mitigating action as the FERC staff notes. Both standards clearly require action “as soon as possible” or “without delay,” but a compliance violation occurs only after 30 minutes has passed.

NERC committees and subcommittees have debated the “as soon as possible” topic for years and have never found a better way to articulate a requirement that allows the system operator the leeway to decide the best course of action.

Next-day planning

IRO-004 addresses next-day operations planning:

IRO-004-0 — Reliability Coordination — Operations Planning. R1. Each Reliability Coordinator shall conduct next-day reliability analyses for its Reliability Coordinator Area to ensure that the Bulk Electric System can be operated reliably in anticipated normal and Contingency event conditions. The Reliability Coordinator shall conduct Contingency analysis studies to identify potential interface and other SOL and IROL violations, including overloaded transmission lines and transformers, voltage and stability limits, etc.


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R2. Each Reliability Coordinator shall pay particular attention to parallel flows to ensure one Reliability Coordinator Area does not place an unacceptable or undue Burden on an adjacent Reliability Coordinator Area.

R3. Each Reliability Coordinator shall, in conjunction with its Transmission Operators and Balancing Authorities, develop action plans that may be required, 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.

It would appear that these standards address the FERC staff’s comments regarding the requirements for next-day reliability studies. As to the staff’s concerns that IRO-004 does not “…require that the system be assessed in the next-day planning analysis to identify the control actions needed to bring the system back to a stable state, with an effective implementation time of within 30 minutes, so that the system will be able to withstand the next contingency without cascading,” we should discuss whether this is a useful requirement considering that the “next hour” may look quite different than predicted the previous day.

1. Is there a more specific (and measurable) way to state “as soon as possible,” or “without delay?”

2. Does the industry need a standard on manual load shedding parameters (amount of load and maximum time to shed load)?

3. Should NERC standards require more specific operating options in the next-day analysis?


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Issue 8. Use of TLR to Address SOL or IROL Violation (OC)

FERC Staff Comments (p. 18) The Blackout Report also recommended that transmission line loading relief (TLRs) not be used in situations involving an actual violation of a SOL or IROL (Recommendation Number 31), but the standards do not yet reflect this recommendation.

(p. 69) Transmission Loading Relief (TLR) procedures are used to relieve overloads on transmission facilities by curtailing and adjusting transactions. The existing TLR procedures, with the exception of the last step invoking load shedding, are likely incapable of being implemented quickly enough to achieve the desired goal of relieving IROL violations in less than 30 minutes. In reviewing the control area and Reliability Coordinator transcripts from August 14, 2003, the Task Force concluded that the TLR process is “cumbersome, perhaps unnecessarily so, and not fast and predictable enough for use in situations in which an Operating Security Limit [SOL] is close to or actually being violated.” The Task Force also recommended that NERC “[c]larify that the transmission loading relief (TLR) process should not be used in situations involving an actual violation of an Operating Security Limit [SOL].” The current IRO standards allow the utilization of the TLR procedure to mitigate potential and actual SOL or IROL violations on any transmission facility. The IRO standards could potentially lead system operators to inappropriately use transmission loading relief procedures to mitigate actual IROL violations. In doing so, valuable time that could be utilized to re-adjust the system by other, more effective, operating measures would be lost.

(pp. 72-73) [EOP-006-0] does not address the concerns expressed in the Blackout Report that call for “clarify[ing] that the transmission loading relief (TLR) process should not be used in situations involving an actual violation of an Operating Security Limit [SOL].” While the intent of the standard as expressed in the Purpose statement is appropriate, Requirement R2 could lead reliability entities to deploy inappropriate operating measures, such as TLR procedures, to mitigate actual IROL violations. Staff’s concerns regarding this standard are more fully addressed in the Primary Issues section of this chapter under the heading “Use of Transmission Loading Relief.”

(p. 63) The standards allow modifications to be made to Interchange Transactions in order to address actual System Operating Limit (SOL) or Interconnection Reliability Operating Limit (IROL) violations. Considering the specific requirements on Tag modification, submission, assessment, approvals and transaction implementation, the total time necessary to implement the Interchange Transactions modification is expected to exceed by a substantial amount the timeframe of 30 minutes that is established in other standards, i.e., the requirement that the system be returned to a secure operating state from a SOL/IROL violation as soon as possible, but no later than 30 minutes after the violation. The standards currently do not contain a clear warning of this potential limitation and therefore could lead to the inappropriate use of transaction modification by reliability entities to deal with actual SOL/IROL violations. In doing so, valuable time would be lost that is needed to re-adjust the system effectively using other operational corrective actions.


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Thoughts from the PC and OC Secretaries The TLR Procedure curtails bilateral transactions, which, in effect, causes a generation redispatch that changes the flow patterns on the transmission system. The curtailments are based on a power flow model of the Eastern Interconnection (albeit rather coarse), and they should therefore reduce the loading on those lines over which the transactions are actually flowing.

The TLR Procedure was never intended as the method for mitigating System Operating Limit or Interconnection Reliability Operating Limit violations. Other options, such as local or market area redispatch, transmission reconfiguration, voltage reductions, and load shedding, are more precise, quicker, and provide more effective ways for system operators to comply with the 30-minute IROL violation limits.

On the other hand, these options we just listed require “local” actions to mitigate transmission congestion even when the flows contributing to that congestion originate in bilateral transactions that are using transmission service on parallel paths. The TLR Procedure is the only NERC standard that can “reach out,” so to speak, and cause a generation redispatch in other areas of the Interconnection to relieve these parallel flows.

Experience shows, as the Commission staff points out, that system operators cannot, and should not, depend on the TLR procedure to quickly reduce flows over the transmission system. Do we therefore conclude that the TLR Procedure “…should not be used in situations involving an actual violation of an Operating Security Limit [Interconnection Reliability Operating Limit]” as the Blackout Report recommends? Indeed, situations are possible where there is no effective local procedure to mitigate an Interconnection Reliability Operating Limit other than transaction curtailment relief through the TLR Procedure, or transmission reconfiguration. While the TLR Procedure is not speedy, by continuing to curtail transactions, it can effectively prevent the overload from recurring.

1. Are there situations where the TLR Procedure should not be used?

2. IRO-006 already advises that “The Reliability Coordinator needs to direct Balancing Authorities and Transmission Operators to execute actions such as reconfiguration, redispatch, or load shedding until relief requested by the TLR process is achieved.” Does this standard need additional explanations?


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Issue 9. Training (OC)

FERC Staff Comments (p. 18) [T]he Blackout Report found that “deficiency in training contributed to the lack of situational awareness and failure to declare an emergency on August 14 while operator intervention was still possible (before events began to occur at a speed beyond human control).” The Task Force therefore recommended that the standards contain requirements for formal training programs, including specified minimum training requirements (Recommendation Number 19). However, the reliability standards do not fully implement this recommendation. Although Personnel Performance standards PER-002 to PER-004 set forth broad objectives that a training program must satisfy, they do not specify the minimum expectations of a training program or the minimum number of hours of training (other than a requirement of five days per year for realistic simulation training) consistent with the roles, responsibilities and authorities of operating and support personnel. Therefore, the nature, objective, and criteria of operator training programs and minimum hours of training are open to interpretation. This lack of specificity allows programs to vary widely with each Transmission Operator or Balancing Authority and still comply with the standards.

(pp. 87-89) The Blackout Report reviewed several previous major North American outages and concluded that inadequate operator training was a contributory factor that the August 14, 2003 Blackout had in common with earlier major outages. The Blackout Report identified training-related recommendations made in studies of major outages:

• Thorough programs and schedules for operator training and retraining should be vigorously administered.

• A full-scale simulator should be made available to provide operator training personnel with “hands-on” experience in dealing with possible emergency or other system conditions.

• Procedures and training programs for system operators should include anticipation, recognition, and definition of emergency situations.

Inadequate Operator training has contributed to several of the past major system disturbances. In the Blackout Report, the Task Force stated that some Reliability Coordinators and Control Area Operators did not receive adequate training in recognizing and responding to system emergencies. In fact, the “deficiency in training contributed to the lack of situational awareness and failure to declare an emergency on August 14 while operator intervention was still possible (before events began to occur at a speed beyond human control).” According to the Blackout Report, the improvement of near-term and long-term training and certification requirements for operators, reliability coordinators and operator support staff will aid in the proper recognition and adequate response to emergencies. The Task Force suggested that NERC require training for the planning staff at control areas and Reliability Coordinators concerning power system characteristics and load, VAr, and voltage limits to enable them to develop rules for operating staff to follow. In addition, the Task Force urged NERC to “require control areas and reliability coordinators to train grid operators, IT support personnel and their supervisors to recognize and respond to abnormal automation system activity.” Further, NERC was advised by the Task Force to “commission an advisory report by an independent panel to address a wide range of issues concerning reliability training programs and certification requirements.” The existing NERC standards do not address these conclusions identified in the Blackout Report.


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(pp. 47-48) System operators need common definitions for normal, alert, and emergency states to enable them to act appropriately and consistently as system conditions change. Alert and emergency states may result from either resource deficiencies and/or transmission contingencies. The Blackout Report states that

On August 14, the principal entities involved in the Blackout did not have a shared understanding of whether the grid was in an emergency condition, nor did they have a common understanding of the functions, responsibilities, capabilities, and authorities of reliability coordinators and control areas under emergency or near-emergency conditions.

To address this concern, Recommendation Number 20 of the Blackout Report recommended establishing “clear definitions for normal, alert and emergency operational system conditions.” It also recommended clarifying “roles, responsibilities and authorities of reliability coordinators and control areas under each condition.” This group of standards does not clearly define transmission-related system states, entry conditions for alert and emergency states, or who has the authority to declare them.

(p. 53) [EOP-005-0] requires a restoration plan to reestablish the electrical system in a stable and orderly manner in the event of a partial or total shutdown. While the standard requires that operators be trained in the implementation of the restoration plan, it does not require this to be done periodically.

(p. 86) In its review, staff identified three PER standards that contain technical issues either because they may be incomplete or lack specificity and therefore might not adequately protect the reliable operation of the Bulk-Power System. Some of the standards fail to address the knowledge gained from past operating incidents. Other reliability standards are ambiguous regarding the requirements for compliance. In addition, the applicability of two of the reliability standards appears to be too narrow in scope.

(p. 87) The Personnel Performance, Training and Qualifications reliability standards require each Transmission Operator and Balancing Authority to have training programs for all of their operating personnel who occupy positions that either have the primary responsibility, directly or through communication with others, for real-time operation of the interconnected Bulk Electric System or who are directly responsible for complying with the NERC reliability standards. However, Transmission Operators and Balancing Authorities are not the only entities that have operating personnel who, directly or indirectly, have the capacity to impact the reliable operation of the Bulk-Power System or who are directly responsible for complying with the reliability standards. Reliability Coordinators, Generator Operators, Operations Planning, and Operations Support staff also potentially impact the reliable operation of the Bulk-Power System yet these entities are not required by the existing standards to participate in a mandatory training program consistent with their roles, responsibilities, authorities and tasks.

The PER standards do not require training programs tailored to the needs of the respective functions with differing authorities, responsibilities, roles and tasks. The standards require that each Transmission Operator and Balancing Authority provide a training program for all specified operating personnel to ensure their operating proficiency. While this standard sets out broad objectives that a training program must satisfy, it does not specify the minimum expectations of a training program or the minimum number of hours of training (other than a requirement of five days per year for realistic simulation training) consistent with the roles, responsibilities and authorities of operating and support personnel. Therefore, the nature, objective, and criteria of operator training programs and minimum hours of training


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are open to interpretation. This lack of specificity allows programs to vary widely with each Transmission Operator or Balancing Authority and still comply with the PER standards.

Staff notes that EPAct 2005 contains a provision for training guidelines for non-nuclear electric energy industry personnel. The training guidelines outlined in EPAct 2005 apply to workers engaged in the construction, operation, inspection or maintenance of non-nuclear electric generation, transmission or distribution systems and include, among others, requirements for competency, initial certification, assessment, and re-certification.

Additionally, staff notes that there is a widely-accepted Systematic Approach to Training (SAT) methodology that has been successfully used in the electric industry as well as other industries. SAT is credited with ensuring that training is conducted efficiently, effectively and directly related to the needs of the position in question. Staff notes that the training program specifics in the standard might be greatly enhanced by considering some of the objectives and elements of the widely-accepted SAT concept.

(pp. 89-90) These [PER] standards require each Transmission Operator, Balancing Authority and Reliability Coordinator to staff all operating positions that have a primary responsibility for real-time operations or are directly responsible for complying with the reliability standards with NERC-certified staff. Generator Operators, who have responsibility for the real-time operation of the Bulk Electric System and are directly responsible for complying with NERC reliability standards, are not similarly required to be NERC-certified. Moreover, these standards do not specify the competencies operating personnel must demonstrate to meet the certification requirements. NERC’s System Operator Certification Program Manual outlines the requirements for certification, but the manual is not part of the standard and therefore is not enforceable.

(p. 90) Reliability Coordinators, Generator Operators, Operations Planning and Operations Support staff are not included in this training requirement. [PER-002-0] does not specify minimum training programs, nor does it tailor training programs according to the needs of Reliability Coordinators, Balancing Authorities, Transmission Operators, Generator Operators, and Operation Planning and support personnel with differing authorities, responsibilities, roles and tasks. Further discussion is provided above in section B.2 entitled, “Training Program Objectives.”

(p. 91) Most of [EOP-004-0] addresses training issues, yet there is no requirement for a formal training program for Reliability Coordinators that is similar to the program required for Transmission Operators under standard PER-002-0.







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Thoughts from the PC and OC Secretaries The FERC staff assessment frequently cites the lack of sufficient operator training standards. Immediately after the 2003 Blackout Report identified a lack of operator training as one of the four root causes of the blackout, NERC began developing a training standard and program based on the Systematic Approach to Training, which the Commission staff recommends on page 89 of its assessment.

Using the SAT means that system personnel are trained on what they need to know to do their job tasks. The employer must first determine what its operating personnel do (the tasks they perform), what they are expected to do (may not be the same as what they do!), what knowledge they already have, and the gaps in that knowledge. The employer must then tailor its training program to fill the knowledge gaps.

This means that if NERC is to successfully implement standards based on the SAT concepts, 1.) our training standards should not specify particular training topics or training methods for the industry in general, and 2.) individual organizations must tailor their training programs to meet the needs of their operating personnel.

NERC agrees that the current PER standards lack specificity, but not necessarily for the reasons that the FERC staff suggests. The staff’s concern that “This lack of specificity allows programs to vary widely with each Transmission Operator or Balancing Authority and still comply with the PER standards” conflicts with the concepts of the Systematic Approach to Training that both NERC and the FERC staff support.

The proposed new NERC training standard will require operating organizations to establish their own SAT. And this means that the compliance measures will be based on the degree to which the organization successfully implements the five phases of the SAT rather than whether the employer trained its personnel on a particular set of concepts or actions that NERC specifies.

NERC also points out that beginning this fall, its Personnel Certification Program will require that operating personnel obtain the following number of continuing education hours every three years to maintain their certification credentials:

• 200 CEH for Reliability Operator (such as a Reliability Coordinator)

• 160 CEH for Balancing, Interchange, and Transmission Operator

• 140 CEH for Balancing and Interchange Operator

• 140 CEH for Transmission Operator

The systematic approach to training

The Systematic Approach to Training or SAT is a methodology for managing training programs. It is an orderly; logical approach to determining what people must know and do at a particular job or in a specific profession. The systematic approach to training ensures that people are prepared for their work by having the necessary knowledge, skills, and attitudes to do their job.

SAT is performance-based training and competency driven. It is concerned with on the job performance. SAT begins with identifying people's work related needs. It ensures training is delivered properly; the student learns what is important; and the student is competent to be assigned to work. The systematic approach to training uses constant evaluation of the training program to ensure it is meeting the needs of the students and of the organization.

There are five phases in the systematic approach to training: Analysis, Design, Development, Implementation, and Evaluation.

AIP Associates www.alwaysimproving.com

©William H. Lowthert


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Issue 10. Backup Control Centers (OC)

FERC Staff Comments (p. 49) The primary control center may become inoperable either as a result of the need to evacuate the control center – for example, because of some environmental or security threat – or because of damage to the control center facilities due to natural or man-made disasters. In the former case, back-up capabilities may rely on the critical functionalities (data, tools, voice) of the primary control center. In the latter case, however, the back-up capabilities must be completely independent of the primary control center to ensure continued reliable operations. While evacuations may require back-up capability only for a few hours or days, damage to the primary control center may require operation from back-up capabilities for a prolonged period of time, possibly measured in months. Failure to provide adequate back-up capability and periodically test its effectiveness, and failure to periodically test the competency of operators to function from the back-up capability can have serious reliability impacts should the primary control center become inoperable for a prolonged period of time. These [EOP] standards do not address the requirements for independence from the primary control center, provide for prolonged operation or provide the minimum tools and facilities consistent with the roles, responsibilities and tasks of the different entities. Staff recognizes, however, that when addressing back up capability for prolonged periods, the standards should reflect an appropriate balance between the probability of needing such back up capability and the consequences to reliability of not having back up capability.

(p. 54) [EOP-008-0] requires a backup plan but does not specifically require that back-up capabilities be provided. As discussed in the Primary Issues section B4 above, this standard does not address the requirements for independence from the primary control center, provide for prolonged operation or provide the minimum tools and facilities consistent with the roles, responsibilities and tasks of the different entities.






Thoughts from the PC and OC Secretaries A Transmission Operator or Reliability Coordinator or Balancing Authority, must be able to perform its tasks “24/7.” While one could argue that a “small” Balancing Authority or Transmission Operator could successfully operate its system manually in an emergency from control rooms at its power plants and substations, larger systems probably cannot, and as Balancing Authority Areas, Market Areas, and Reliability Coordinator Areas grow, backup control centers become necessities.

NERC standards require provisions for backup facilities or plans for operating in event the control center becomes inoperable, but do not specifically require backup control centers:


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IRO-002-0 — Reliability Coordination — Facilities. R8. Each Reliability Coordinator shall continuously monitor its Reliability Coordinator Area. Each Reliability Coordinator shall have provisions for backup facilities that shall be exercised if the main monitoring system is unavailable. Each Reliability Coordinator shall ensure SOL and IROL monitoring and derivations continue if the main monitoring system is unavailable.

EOP-008-0 — Plans for Loss of Control Center Functionality. R1. Each Reliability Coordinator, Transmission Operator and Balancing Authority shall have a plan to continue reliability operations in the event its control center becomes inoperable. The contingency plan must meet the following requirements (listed in R1.1 through R1.8).

NERC readiness audit teams visit control center backup facilities, and the audit reports provide the teams’ assessments of the backup capabilities—how far away, how well equipped, how capable.

1. Should NERC standards require backup control centers for Transmission Operators, Balancing Authorities, and Reliability Coordinators?

2. If so, to what extent should those standards define the functional specifications for these backup control centers?

3. How should the standards, as the FERC staff notes, “reflect an appropriate balance between the probability of needing such back up capability and the consequences to reliability of not having back up capability?”


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Issue 11. Transmission Performance (Planning) Criteria (PC)

FERC Staff Comments (p. 21) The Transmission Planning standards … contain technical deficiencies, vague language that could be subject to multiple interpretations. For example, Standard TPL-002-0 requires a Planning Authority and Transmission Planner to demonstrate that its portion of the interconnected transmission system can meet projected customer demands and projected firm transactions while capable of withstanding the Category B contingencies.

The TPL Category B contingencies only include loss of a single element, defined as a generator, transmission circuit, transformer, or single DC pole with or without a fault. This definition does not cover all of the single element failures that are known to occur in actual operation. The unanticipated failure of some single elements in the Bulk-Power System can result in the loss of multiple elements. Because of the resulting impact on reliability of the loss of more elements than those defined in Category B, some Regions base their groupings according to the event, irrespective of the number of elements forced out of service. For such a Region, a single event that results in the loss of multiple elements (e.g., a relay failure that forces a DC bi-pole out of service or a lightning strike that simultaneously forces both circuits of a double circuit tower line out of service) are grouped alongside those events which would result in loss of single elements, such as a generator, transmission circuit or transformer, in essence providing a more stringent level of reliability.

With such variation in criteria, what is acceptable in one Region is not acceptable in another Region for reasons related to historical adoption of reliability criteria and practices rather than geography or system topology. The result could be that some Regions have differentiated and higher standards than others.

(p. 109) In carrying out power systems simulations to determine the need for system upgrades or reinforcements with sufficient lead time to implement, it is important to ensure that the system under study is sufficiently stressed so that any underlying weaknesses or deficiencies can be identified. It is equally important to test the performance of the system under study for a wide variety of probable scenarios. Such scenarios would typically simulate a range of generation dispatches including generator outages, a range of demand levels and load power factors, a range of transactions and a range of transmission outages including reactive power devices. Such simulations would determine the most onerous set of system conditions, which might not be peak demand conditions. In addition, these tests would identify requirements for generators that must run to remove local transmission constraints, or alternatively identify the inability to deliver generation to load due to insufficient transmission capacity. These are especially important for the near term (one to five years), as the results would be instructive to seasonal, monthly, weekly and day-ahead operations planning studies and as both aspects are critical to reliable operations in real time. Adherence to applicable reliability criteria for the overall set of simulations provides a good indication of the ability of the system to remain reliable for a variety of operating conditions.

The [TPL] standards require entities to “cover critical system conditions and study years,” but they do not require that sensitivity studies be carried out, nor do they specify the rationale for determining critical system conditions and study years. System conditions are as important as contingencies in evaluating the performance of present and future systems.


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(pp. 110-112) The Planning Standards require demonstration through valid assessments that the system is planned so that it can be operated to supply projected customer demands and firm Transmission Services at all demand levels under a set of contingencies as defined in Table 1 (Transmission System Standards – Normal and Emergency Conditions) of the TPL Standards. Table 1 is a key part of the Planning Standards and lays out the system performance requirements for a range of contingencies grouped according to the number of elements forced out of service as a result of the contingency. For example: Category A applies to the normal system with no contingencies; Category B applies to contingencies resulting in the loss of a single element defined as a generator, transmission circuit, transformer, single DC pole with or without a fault; Category C applies to a contingency resulting in loss of two or more elements, such as any two circuits on a multiple tower line or both poles of a bi-polar DC line; while Category D applies to extreme contingencies resulting in loss of multiple elements, such as a substation or all lines on a right-of-way. The system performance expectations for Category C contingencies are lower than those for Category B contingencies, in that they allow unspecified amounts of planned or controlled loss of demand.

The term “Reliable Operation” as set forth in section 215(a)(4) of the FPA is defined as:

Reliable Operation means operating the elements of the Bulk-Power System

within equipment and electric system thermal, voltage, and stability limits so that

instability, uncontrolled separation, or cascading failures of such system will not

occur as a result of sudden disturbance, including a Cybersecurity Incident, or

unanticipated failure of system elements.

Staff interprets this to mean that any element in the actual Bulk-Power System may fail and contingencies used in simulations should be consistent with what can occur in real-time operations based on the actual details of the Bulk-Power System.

As stated above, Table 1 of the Planning Standards lays out the system performance requirements for a range of contingencies. There are a number of footnotes associated with Table 1 meant to aid in the interpretation of the performance requirements. For example, the Requirements in Category B are no load loss or curtailment of firm transfers from contingencies resulting in the loss of a single element. But footnote (b) appended to these Requirements states in part “[p]lanned or controlled interruption of electrical supply to radial customers or some local Network customers, connected to or supplied by the faulted element or affected area, may occur in certain areas without impacting the overall reliability of the interconnected transmission systems.” This footnote is sufficiently ambiguous to allow differing interpretations. One interpretation of this statement is that load interruption for a single contingency is permitted, while another interpretation is that the practice is the exception rather than the rule, and for this reason load interruptions are not permitted for a single contingency except in very special circumstances where such interruption is limited to the firm load directly associated with the failure. In the case of the former interpretation, applicable entities may argue that they can deliberately interrupt firm load customers as a result of the loss of a single contingency without violating any reliability standards.

Other footnotes are also ambiguous and as such detract from the intent of the performance requirements stated in Table 1. They should be clarified so that they are applied appropriately and consistently by all the entities to whom they apply.


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Extreme events are low probability but high impact events. Examples provided by NERC in the standards include loss of a substation, loss of all generating units at a station, loss of all transmission lines on a right-of-way, etc. Extreme events must be assessed to evaluate their risks and consequences. While the standards require such assessments, documentation of the results and submission to the RRO, they do not require that consideration be given either to reducing the probability of the loss of multiple elements or mitigating the impact. Furthermore, the standards do not explicitly require that the results of these assessments be shared with impacted entities or communicated to operations planning staff and control room operators.

Staff notes that a number of high-risk weather events, such as the hurricanes that impacted the Southern United States and an ice storm that impacted Canada, resulted in a greater impact on the Bulk-Power System in terms of the number of elements lost than the scenarios identified in the standards.






Thoughts from the PC and OC Secretaries The NERC Planning Committee is addressing these issues. The Committee’s recently completed report, “Evaluation of Criteria, Methods, and Practices Used for System Design, Planning, and Analysis in Response to NERC Blackout Recommendation 13c,” (See text box at right) includes:

• Contingencies analyzed

• Load levels studied

• Voltage limits applied

• Methods utilized for rating conductors and other equipment

• Interchange modeling

• Generation dispatch practices

• Substation configurations

The Planning Committee believes that Regional planning processes are adequate from the perspective of planning a reliable bulk electric system. Nevertheless, as the committee’s report points out, there are opportunities for improvement. For instance:

• Table I of the NERC standards TPL-001-0 through TPL-004-0, System Performance…, is being interpreted differently by various planners.


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• TPL-001-0 through TPL-004-0 standards could be improved by incorporating additional requirements.

• Good practices identified in several regional or individual planning processes should be considered by the regions to enhance existing processes.

• The requirements of standards FAC-008-1, Facilities Ratings Methodology, and FAC- 0090-1, Establish and Communicate Facility Ratings, adequately address the issue of transmission facility rating methods and practices, and the sharing of consistent rating information.

Among the report’s many recommendations are these specific suggestions for revising NERC’s TPL standards:

“There is a need to clarify some of the standards, particularly TPL-001-0 through

TPL-004-0 (Appendix B) and the corresponding Table I (Appendix C), as well as

a need to incorporate additional requirements into some of these standards. The

TIS believes that these clarifications and additional requirements should be

incorporated in the NERC standards through the NERC Standards Development

Process.

“There are eleven (11) recommendations in this category which are described in

Chapter 4, Section A, NERC Standards Activity. Recommendations A1–A5

describe clarifications that would assist the industry in consistent application of

Table I. Recommendations A6 – A10 describe new requirements for the TPL

standards that would provide for additional documentation of the processes and

assumptions used by transmission planners, or for clarification of existing

requirements. Recommendation A11 relates to the generator parameter

verification standards in the Phase III/IV group of standards for which TIS has

provided comments during the development process.”

At this point, we expect the Planning Committee (or its subgroups) to submit standards authorization requests to revise the NERC reliability standards.


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Issue 12. Determination of Facility Ratings (PC)

FERC Staff Comments (p. 18) Staff also is concerned that, although the Blackout Report recommended the development of uniform and consistent methodologies for transmission line and equipment ratings (Recommendation Number 27), the reliability standards do not yet include such a requirement.

(p. 58) Under current utility practices, there is no uniform set of methodologies that are used by the reliability and operating entities to determine equipment ratings. This has frequently resulted in different ratings for the same equipment under the same ambient and operating conditions in the same region. It is possible that two transmission owners with joint ownership of an interconnection line using their respective methodologies could derive two different line ratings, even with both applying the same assumptions in ambient and operating conditions.

The standards for determining facility ratings do not establish a uniform or consistent set of methodologies; instead they only require Transmission Owners or Generation Owners to document its chosen methodology. The standards do not address Recommendation Number 27 of the Blackout Report that NERC “develop clear, unambiguous requirements for the calculation of transmission line ratings.”

(p. 60) The concerns discussed in section B.3 above, regarding facility rating methodologies, are at issue in [FAC-008-1]. This standard does not provide a uniform or consistent set of methodologies; instead it only requires equipment owners to document the respective methodologies they use. Therefore, this standard does not appear to address Recommendation Number 27 of the Blackout Report to establish “clear, unambiguous requirements” for the calculation of transmission line ratings.







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Thoughts from the PC and OC Secretaries NERC’s standards are based upon the premise that the equipment owner (Transmission Owner or Generator Owner) is both entitled and obliged to set the ratings for its equipment. The Reliability Coordinators, Transmission Operators, and Balancing Authorities use those ratings to calculate other operating limits, such as System Operating Limits, Interconnection Reliability Operating Limits, Transfer Capabilities, Available Transfer Capabilities, ramping limits, and relay settings. (See diagram at right)

The equipment owner is responsible for its equipment’s maintenance, protection, repair, and replacement. One would expect, for example, that a transmission owner would rate its equipment to maximize the owner’s transmission revenues and minimize its risks and maintenance costs. Likewise for generator owners.

NERC standards require that the equipment owner document its facility ratings methods:

FAC-008-1 — Facility Ratings Methodology. R1. The Transmission Owner and Generator Owner shall each document its current methodology used for developing Facility Ratings (Facility Ratings Methodology) of its solely and jointly owned Facilities. The methodology shall include all of the following:

R1.1. A statement that a Facility Rating shall equal the most limiting applicable Equipment Rating of the individual equipment that comprises that Facility.

R1.2. The method by which the Rating (of major BES equipment that comprises a Facility) is determined.

R1.2.1. The scope of equipment addressed shall include, but not be limited to, generators, transmission conductors, transformers, relay protective devices, terminal equipment, and series and shunt compensation devices.

R1.2.2. The scope of Ratings addressed shall include, as a minimum, both Normal and Emergency Ratings.

R1.3. Consideration of the following:

R1.3.1. Ratings provided by equipment manufacturers.

R1.3.2. Design criteria (e.g., including applicable references to industry Rating practices such as manufacturer’s warranty, IEEE, ANSI or other standards).

R1.3.3. Ambient conditions.

R1.3.4. Operating limitations.

R1.3.5. Other assumptions.

Transmission Owners andGenerator Owners

Provide Equipment Ratings to

Reliability CoordinatorsTransmission OperatorsBalancing AuthoritiesTransmission Service Providers

TTCATCSystem Operating LimitsInterconnection ReliabilityOperating Limits

Who Calculate


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NERC standards also require equipment owners to coordinate the ratings of jointly-owned facilitates, reducing the likelihood of deriving two different transmission line or generator ratings:

FAC-004-0 — Methodologies for Determining Electrical Facility Ratings. R.1.4. Ratings of jointly-owned and jointly-operated facilities shall be coordinated among the joint owners and joint operators resulting in a single set of Ratings.

The FERC staff assessment refers to “reliability and operating entities,” and we interpret these entities as the Reliability Coordinators, Transmission Operators, and Balancing Authorities. These entities may not own the equipment they are operating. Therefore, while they do calculate system limits, it would not seem appropriate for them to calculate equipment limits. (NOTE: We must remember that an organization can “roll up” several functions and can be a Transmission Owner AND a Transmission Operator AND a Transmission Service Provider.)

1. Does FAC-008 provide sufficient guidance to the Transmission Owner and Generator Owner?

2. Should NERC standards explicitly require the equipment owner to use, rather than just “consider,” one of the ratings methods listed in R1.3.1 through R1.3.5?

3. Do the standards adequately cover the linkages between the equipment ratings that the Transmission Owner and Generator Owner provide, and the system limits and transfer capabilities that the Reliability Coordinator, Transmission Operator, Balancing Authority, and Transmission Service Provider calculate?


Functional Model Revisions Functional Model Working Group Chairman Jim Cyrulewski will review in the joint session the salient changes to the Functional Model, which NERC has posted for a 45-day comment period (comments are due by June 23.) The working group will bring the final version to the Operating Committee (OC) and Planning Committee (PC) for approval, and then to the Board of Trustees. The following documents will be provided with the agenda for the joint session:

• Functional Model – Version 3 draft • Functional Model Version 3 and Regional Reliability Plan Guideline Summary • Regional Reliability Plan Guideline Draft

PC Discussion Stan Kopman will lead the discussion in the PC meeting on those aspects of the Functional Model revisions relevant to the PC. The diagram of the Functional Model below points out the changes needed to be discussed.

New

RA→ RC

Revised process

PA→PC

Revised relationto the RC

New

RA→ RC

Revised process

PA→PC

Revised relationto the RC

2

Regional Reliability Plan Guideline The Regional Reliability Plan Guideline is not a part of the Functional Model, but is related to the model. The Regional Reliability Plan requires each regional reliability organization to list the responsible entities as defined in the model and explain how those entities interrelate.

The regions will file these plans with NERC. The OC will approve the operating section of the plan, and the PC will approve the planning section. Action Required: Discuss


Compliance Review Group Background As part of the NERC Compliance Enforcement Program (CEP), the Compliance Review Group (CRG) has been requested by the Compliance and Certification Managers Committee (CCMC) to monitor the compliance of specific NERC reliability standards that apply to the regions. The CCMC will consider the CRG’s compliance recommendations, and input from the regions, in making the final decision regarding regional compliance. In the 2005 Compliance Enforcement Program the two standards are as follows:

• PRC-002-0 — Define and Document Disturbance Monitoring Equipment Requirements requires each region to develop comprehensive requirements for the installation of disturbance monitoring equipment to ensure data is available to determine system performance and the causes of system disturbances.

• PRC-014-0 — Special Protection System Assessment requires each region to assess the operation, coordination, and effectiveness of all special protection systems installed in its region at least once every five years for compliance with NERC reliability standards and regional criteria.

In the 2006 Compliance Enforcement Program the three standards are as follows:

• PRC-003-0 — Regional Procedure for Transmission Protection System Misoperations requires each region to ensure all transmission protection system misoperations are analyzed for cause and corrective action, and maintenance and testing programs are developed and implemented.

• PRC-012-0 — Special Protection System Review Procedure requires each region to ensure that all Special Protection System (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. In addition each region shall assure that maintenance and testing programs are developed and misoperations are analyzed and corrected.

• PRC-013-0 — Special Protection System Database requires each region to ensure that all Special Protection System (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems.

Status 2005 Compliance Enforcement Program The CRG developed a report highlighting its 2005 findings and recommendations and presented this to the CCMC at its meeting on March 22–23, 2006. The CCMC reviewed and discussed the report; all findings and recommendation were accepted.

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On May 10, 2006, David Hilt, the vice president and director of Compliance, sent letters to each of the regions indicating the findings of the NERC 2005 assessments that were conducted with assistance from the CRG, the Multiregional Modeling Working Group, and the Reliability Assessment Subcommittee. 2006 Compliance Enforcement Program An e-mail ballot was conducted by the CCMC in the beginning of April 2006 to approve the 2006 implementation plan for the CRG (Attachment A). The plan was approved by a vote of 8–0. NERC has reached out to the CRG members to determine their availability to continue participation on the CRG in 2006. As a result, three members indicated that they are willing to remain active members on this group. In the upcoming weeks, NERC will determine what additional resources are need to populate the CRG, and will then seek the support and guidance of the Planning Committee. Action Required: None

NO R T H AM E R I C A N EL E C T R I C R E L I A B I L I T Y CO U N C I L

Princeton Forrestal Vil lage, 116-390 Vil lage Boulevard , Pr inceton, New Jersey 08540-5731



MEMORANDUM

TO: Compliance and Certification Managers Committee FROM: Navin B. Bhatt, Compliance Review Group Chairman DATE: March 22, 2006 SUBJECT: 2006 Compliance Review Group Implementation Plan As requested by the Compliance and Certification Managers Committee, the Compliance Review Group has developed this 2006 implementation plan to monitor compliance with three NERC Reliability Standards that apply to the regions. The Compliance and Certification Managers Committee will consider the Compliance Review Group’s compliance recommendations, and input from the regions, in making the final decision regarding regional compliance. The three NERC Reliability Standards are as follows: PRC-003-0 — Regional Procedure for Transmission Protection System Misoperations requires each region to ensure all transmission protection system misoperations are analyzed for cause and corrective action, and maintenance and testing programs are developed and implemented. PRC-012-0 — Special Protection System Review Procedure requires each region to ensure that all Special Protection System (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. In addition each region shall assure that maintenance and testing programs are developed and misoperations are analyzed and corrected. PRC-013-0 — Special Protection System Database requires each region to ensure that all Special Protection System (SPS) are properly designed, meet performance requirements, and are coordinated with other protection systems. The Compliance Review Group will request from each region an executive summary, along with their materials, stating where specific documentation can be located in the submitted materials that demonstrate compliance with each requirement described in the NERC Reliability Standard. The summary must contain any explanation needed to relate and/or explain how and why the specific documentation demonstrates compliance.

Attachment A (Agenda Item 6a)

Memorandum 2006 Compliance Review Group Implementation Plan March 22, 2006 Page Two

The Compliance Review Group schedule for the 2006 compliance review is as follows: June 2, 2006 — Request to Regions: The regions will be requested to submit, by September 1, 2006, the materials to demonstrate compliance with the following Reliability Standards: PRC-003-0, Requirements 1 and 2; PRC-012-0, Requirements 1 and 2; and PRC-013-0, Requirements 1 and 2. September 1, 2006 — Submittals by Regions: All materials from the regions for the three standards to be received by Sandy Cominski of the NERC staff at [email protected]. November 3, 2006 — Initial Findings: The Compliance Review Group will complete its initial findings. November 17, 2006 — Send Initial Findings to Regions: The factual results of the group’s review of regional submittals will be sent to the regions. The regions are to review these initial findings and provide feedback to the Compliance Review Group. The feedback may include a statement that the region feels a particular standard is not applicable to it, corrections or additions to the original submittal, feedback on the standards, or agreement with the findings. December 15, 2006 — Regional Response/Feedback: Due date for regional response/feedback. January 12, 2007 — Compliance Review Group’s Final Findings: The group to submit its compliance findings and recommendation to the Compliance and Certification Managers Committee. If you have any questions regarding this implementation plan, feel free to contact Mike DeLaura (NERC office), or myself.


General Considerations on the Role of the PC and OC1

At the March PC and OC meetings, we discussed the organization of NERC around six major technical programs, plus a new program on committees and members forums, and four internal functions.

Sam Jones, Scott Helyer, and Don Benjamin explained that each of the technical programs would most likely have one, or maybe more, “program” committees that would develop the policies for that program. We thought of the Planning Committee and Operating Committee as “general” committees, that 1.) served the technical programs when those programs needed the wide diversity of expertise in operations or planning, and 2.) performed other tasks, such as approving reliability plans and reports. We anticipated bringing a “straw man” proposal to the PC and OC in June, with the goal of having the reorganizations in place by this fall.

Meanwhile, the NERC staff had been working on the application to become the ERO. From the comments we received from the PC and OC members in March, including

1 Presented at the June 7, 2006 Joint Session.

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board members who attended those meetings, the staff included the following description of the roles of the PC and OC along with a diagram (on the following page) that shows how these committees help the NERC programs and how the subcommittees fit into the picture.

“These two general technical integration committees and their subgroups provide technical advice and subject matter expert support to each of the NERC program areas; serve as forums for technical discussion and integration of the outputs of each NERC program area; and provide expert technical opinions on reliability matters to the board.” Page 24 of the ERO application

The Stakeholders Committee and Board of Trustees held special meetings on March 28 to discuss and approve NERC’s application to become the ERO. Several members of both of these groups stated quite clearly that the Planning Committee and Operating Committee were critical to NERC’s success and asked that we not rush to change the committee’s structures or membership. Some suggested waiting for at

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least two years, others thought 12 months more reasonable. The sense of the Board is that we should complete our plans for the structure of the PC and OC and bring a new charter to the board for approval in 2007. (All committees will have board-approved charters in lieu of today’s scopes.)

Therefore, based on these meetings, a number of discussions with individuals on the PC and OC, and the roles of the PC and OC contained in the ERO application, we suggest moving more slowly on modifying the PC and OC and allowing these two groups to evolve as the ERO establishes itself and identifies its needs for these two committees. In the short term, the PC and OC must continue performing their ongoing responsibilities, and we can also start working on those changes that we can identify and accommodate now within the existing structure and membership of these committees.

Generally speaking, we need to address four major sections that comprise the PC and OC charters:

1. Goals

• Enhancing reliability. How the PC and OC helps the ERO enhance the reliability of the grid.

• Role in serving ERO programs. The role that the PC and OC play in meeting the needs of the ERO’s programs.

2. Responsibilities and accountabilities.

• Responsible to the Board. The PC and OC are responsible for providing advice to the board, either at the board’s request, or on the initiative of the committee. This includes integrating the “deliverables” from the NERC programs.

• Responsible to the ERO. The PC and OC are responsible for specific tasks for the ERO in general.

• Responsible to the programs. The PC and OC are responsible for serving the needs of the ERO’s programs by aggregating the collective wisdom of a wide diversity of members and stakeholders that make up NERC.

3. Membership

• Diversity and Expertise. How the committee’s members will include the necessary expertise with a sufficient diversity of opinions to avoid the committee polarizing on issues.

• Member expectations. Committee members will actively participate on the committee by:

• Attending committee meetings,

• Bringing their own personal knowledge to the committee,

We can use the words from the ERO application. Forum for: • Technical advice • Integration • Opinions

Such as reliability plans, Reliability Coordinator plans, field tests, reliability aspects of market plans, reliability assessments, Functional Model.

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• Bringing the perspective of their segment to the committee,

• Working toward consensus to help the industry enhance grid reliability.

4. Organization and Procedures

• Subgroups. What subgroups the PC and OC will depend on.

• Procedures. How the PC and OC manage their work, including the role of the subgroups, staff, officers, and so forth.

At this meeting, we should discuss the following from each of these sections and decide on our next steps:

1. How the PC and OC can integrate the “deliverables” from the other programs to provide advice to the programs, board, and industry. This meeting agenda attempts to do this by reviewing the 2005 fourth quarter compliance report, the vegetation management compliance report, and the NERC standards that are in various stages of the standards development process.

2. The specific tasks that the PC and OC are responsible for. For example, the Operating Committee is responsible for approving:

• Regional Reliability plans

• Reliability Coordinator plans

• The reliability aspects of certain market procedures

• Field tests (and monitoring their progress)

• Functional Model revisions

3. The role that the PC and OC play in the NERC programs. The NERC staff has some general ideas to offer the OC.

4. PC and OC membership. For now, we’ve asked the PC and OC members to stay in place for another year to maintain continuity through whatever reorganization we need to implement over the next 12 months.

5. Role of the subcommittees. The Operating Reliability Subcommittee, Interchange Subcommittee, Transmission Subcommittee, Reliability Coordinator Working Group, and their various subgroups continue to function as they have been. The ORS and RCWG have been discussing the merits of merging or reformatting their meetings (they meet on adjacent days, and some of the members belong to both groups); so have the Transmission Subcommittee and the PC’s Transmission Issues Subcommittee, who have been meeting with each other. These groups would bring their proposed changes—if any—to the PC and OC.

Action Required: Discuss


Straw Proposal to Rescope and Restructure the PC and to Provide Support for the Reliability Assessment and

Performance Analysis Program The roles and responsibilities of the Planning Committee (PC) and Operating Committee (OC) are being revisited in light of NERC’s transition to the electric reliability organization (ERO). This issue will be presented and discussed in general terms in the joint session on June 7. As stated on page 24 of NERC’s ERO Application, the PC and OC are seen as general technical integration committees, with their subgroups providing technical advice and subject matter expert support to each of the NERC program areas. The PC and OC also serve as forums for technical discussion and integration of the outputs of each NERC program area, and to provide expert technical opinions on reliability matters to the NERC Board of Trustees. The Application goes on to say that as the ERO is implemented, NERC will re-evaluate the structure, role and deliverables of the technical integration committees to ensure that the industry is able to effectively and efficiently provide its expertise in support of NERC’s mission as the ERO. Based on preliminary discussions, one option has emerged that would have the PC serve in the general role described above, but also provide specific support to NERC’s Reliability Assessment and Performance Analysis Program. The general description of this program, as it appears in the Application is:

Reliability Assessment and Performance Analysis — This program comprises several functions critical to continuous reliability performance improvement: (1) independently assessing and reporting on the overall reliability and adequacy of the existing and planned bulk power system, consistent with Section 39.11 of Commission’s Rule; (2) investigating and analyzing off-normal events on the bulk power system to identify the root causes that may be precursors of potentially more serious events, and to disseminate these findings to the industry to improve reliability performance; (3) assessing past reliability performance for lessons learned; and (4) developing reliability performance metrics and benchmarks. This program will make recommendations to the ERO Standards Program for new or revised reliability standards; to the Compliance and Organization Registration and Certification Program for enhanced monitoring efforts; to the Reliability Readiness Audit and Improvement Program for additional elements to include in its on-site audits; and to the Training, Education, and Personnel Certification Program for new or improved training and education programs.

To this end, the straw proposal for discussion by the PC is:

1. Rescope the PC to define its role, along with the OC, in providing both input to the NERC board and technical discussion, integration, technical advice, and subject matter expert support for each of the NERC programs. (This is where the results of NERC standards, compliance, readiness, assessment, events analysis, benchmarking, and

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training programs come together in a forum for "technical integration," technical discussion, and recommendations, either to the board, the programs, or both.)

2. In addition, the PC will be responsible for providing program-specific support to the

Reliability Assessment and Performance Analysis Program.

3. Establish the following subcommittees under the new PC:

Subcommittees to Specifically Support the Reliability Assessment and Performance Analysis Program

a. Reliability Assessment Subcommittee — repopulated to comprise a small group of industry experts who would work with the NERC staff in gathering and analyzing information and preparing NERC’s reliability assessment reports.

b. Events Analysis and Information Exchange Subcommittee (old Disturbance Analysis Working Group) — to support NERC’s Events Analysis and Information Exchange Program.

c. Reliability Metrics and Benchmarking Subcommittee — to support this new program.

Subcommittees to Provide Subject Matter Expert Support to all Programs

d. Transmission Issues Subcommittee —provide subject matter expert advice and recommendations to the PC on all transmission issues; provide program support for a possible future Transmission Availability Data System (TADS) program.

e. Resource Issues Subcommittee — provide subject matter expert advice and recommendations to the PC on all resource issues; provide program support for GADS program.

f. System Protection and Control Subcommittee — provide subject matter expert advice and recommendations to the PC on all aspects of system protection and control as a follow on to work of the System Protection and Control Task Force.

g. Demand Forecasting Subcommittee — provide subject matter expert advice and recommendations to the PC on all aspects of demand forecasting, including forecast bandwidths, forecast sensitivity analyses, retrospective analyses of forecast vs. actual demands, demand response program analyses, etc.

h. Interconnection Studies Subcommittee — share knowledge and experience among the Interconnections in the modeling, model validation, and analysis of Interconnection static and dynamic behavior and performance, and provide subject matter expert advice and recommendations to the PC.

4. PC members will serve as officers of each subcommittee. (This will place an increased

burden on these individuals, but is a necessary part of making sure the committee as a whole stays engaged in subcommittee activities.) Other high-level technical policy types will be added to fill out the committee.

Action Required: Discuss


PC Subgroup Retirements Planning Committee (PC) Chairman Scott Helyer will discuss retiring the following PC subgroups:

Standards Evaluation Subcommittee — individual subcommittees will have responsibility to watch over standards development in their respective subject matter expert areas. Planning Standards Task Force — no longer active. Planning Reliability Model Task Force — functions integrated into new Functional Model Working Group. Compliance Review Group — can be disbanded after it completes the work it has under way for the Compliance Program. Blackout Recommendations Review Task Force — recommendations have already been assigned to other subgroups. Data Review Task Force — assignment completed; Data Coordination Working Group has ongoing responsibilities. ATC Task Force — this was an ad hoc task force formed to assist NERC in preparing a response to a FERC NOI on ATC issues in 2005. Interconnection Dynamics Working Group — responsibilities can be absorbed into a new Interconnection Studies Subcommittee. Wind Generation Task Force — formed to assist NERC in addressing a specific FERC request. Ongoing responsibility for this issue rests with the Transmission Issues Subcommittee.

Action Required: Approve retiring the above-mentioned Planning Committee subgroups.

Documents

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