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 LPr inc e ton F o r re s t a l Vi l l a ge , 116 - 390 Vi l l a ge B ou leva r d , P r ince ton , N ew Je r sey 08540- 5731

Operating Committee Meeting

March 16, 2005 Following Joint Meeting5 p.m.March 17, 2005 8 a.m.5 p.m.

The Westin Long Beach Hotel333 East Ocean Boulevard

Long Beach, California 90802Phone: 562-436-3000 Fax: 562-436-9176

Agenda

1. Administrationa. Arrangements – Secretaryb. Announcement of Quorum – Secretaryc. Procedures Secretary

i) Antitrust Guidelines Chairmanii) Parliamentary Procedures Secretaryiii) Waiver of 10-day Advance Requirement for Motionsiv) Organization and Procedures Manual for the NERC Standing Committees

d. New Members – Secretarye. Introduction of Members and Guests Secretary

2. Approval of Agenda Chairman

3. Consent Agenda Chairmana. Minutes November 10–11, 2004 Operating Committee Meeting Chairmanb. Executive Committee Activities – Sam Jones

4. Information Itemsa. Board of Trustees Highlightsb. Quarterly Disturbance Report

5. Committee Administrationa. Budget Assessment and Cost Allocation Subcommittee – Sam Jones, Michel Armstrong, Bob

Dintelmanb. 2005 and 2006 Work Plans – Secretaryc. Committee Membership Nominations for 2005–2007

6. NERC/NAESB Coordination Items – Secretarya. NERC/NAESB TLR Subcommittee

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b. NAESB Version 0 Standardsc. OASIS Conferenced. Energy Day

7. Reports from Other Committees Glenn Ross

8. Operator Traininga. Operator Training Programb. Continuing Education Program

9. “Best Practices” – Secretary

10. FERC Reactive Power Report

Implementation of Recommendations from August 14, 2003 Blackout

11. Blackout Recommendations: Real-Time Operationsa. Operator “Tools”b. Communications – Hotlinec. Definitions of Operating Conditionsd. TLR Use

12. Blackout Recommendations: Operations Planninga. Operations Planning – Generalb. Identification of “Critical Facilities”c. Communications – Line Outage Information

13. Blackout Recommendations: Restoration

14. Reliability Standardsa. Functional Model – Reliability Standards Coordination – Gerry Cauleyb. Balance Resources and Demand Field Test – Raymond Vice

15. Interconnection Frequency Issues – Carl Monroea. Frequency Errorb. Frequency Responsec. Frequency Analysis

16. EPRI TagNet Presentation – Steve Lee

17. Interconnection-wide Reliability Studies Initiative – Bob Cummings

18. Congestion Managementa. TLR Redispatch Credit – Mike Kormos, Dave Zwergelb. Interchange Distribution Calculator Option 3 Project – Larry Kezelec. Entergy 3% TLR Threshold Test – David McNeill

19. Long-Term ATC/AFC Task Force

20. MISO Market Startup and Standards Waiver Verification – Dave Zwergel

21. Reliability Plans – Secretary

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22. Next Meetings

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Item 1. Administration

a. ArrangementsThe secretary will review the meeting arrangements. The meeting begins on Wednesday, March 16 after the joint OC-PC meeting (or after lunch), and will adjourn on Thursday, March 17 at 5 p.m. A luncheon will be served at noon on both days.

b. Announcement of QuorumThe secretary will announce whether a quorum (two-thirds of the voting members) is in place. NOTE: the committee cannot conduct business without a quorum. Please be prepared to stay for the entire meeting.

The Operating Committee’s Vice Chairman Sam Jones will preside.

c. ProceduresThe NERC Antitrust Compliance Guidelines, Organization and Procedures Manual, and a summary of Parliamentary Procedures are attached for reference. The secretary will answer questions regarding these procedures.

Attachments Antitrust Guidelines

Parliamentary Procedures

Organization and Procedures Manual for the NERC Standing Committees

Action – Waiver of “Ten-Day” rule“Ten-day” rule. The chairman will waive the rule requiring a ten-day posting before an item can be brought to the committee for consideration. (See text at right.) The committee members are free to make any motions they desire.

d. New MembersMr. James Fuhrmann returns to the Operating Committee as MAIN’s regional representative. Mr. Fuhrmann replaces James Maenner.

AttachmentEmail – Richard Bulley to Don Benjamin, March 8, 2004

e. Introduction of Members and GuestsThe chairman will ask the committee members and guests to introduce themselves

AttachmentOperating Committee roster

From Organization and Procedure Manual, “Notice of Committee Agenda:”

“In general, action may not be brought to a vote of the committee unless it has been noticed in a published agenda or other form of distribution to the committee at least ten (10) business days before the meeting date upon which action is to be voted. This requirement for a 10-day notice may be waived either by the approval of the chair or by a two-thirds affirmative vote of the committee’s voting members present at a committee meeting at which a quorum has been established.”

Item 2. Approval of Agenda

ActionApprove meeting agenda.

BackgroundThe chairman will review the agenda, ask for amendments, and then approval.

Item 3. Consent AgendaThe consent agenda allows the Operating Committee to approve routine items that would not normally need discussion. Any OC member may ask the chairman to remove an item from the consent agenda for formal discussion and action.

The “Action” listed in each item would be the result of the committee’s approval of the consent agenda.

a. Minutes November 10–11, 2004 Operating Committee Meeting

ActionApprove minutes.

AttachmentMinutes – November 10–11 Operating Committee meeting

b. Executive Committee ActionsThe Executive Committee did not take any formal actions that need ratification since the last Operating Committee meeting.

Item 4. Information ItemsThese items are listed FYI and we are not planning any formal discussions. However, the NERC staff or subcommittee officers will be prepared to discuss any of these items if the OC wishes.

a. Board of Trustees Highlights

AttachmentHighlights from the February 8, 2005 Board of Trustees meeting.

b. Quarterly Disturbance Report

AttachmentsReport from the Disturbance Analysis Working Group

“Disturbance Analysis Working Group – Quarterly Update”

Item 5. Committee Administration

a. Budget Assessment and Cost Allocation Subcommittee

ActionDiscuss cost and funding issues that WECC and Hydro-Québec representatives bring to the Operating Committee.

AttachmentsLetter – Request for Technical Input

Scope – Budget Assessment and Cost Allocation Subcommittee

BackgroundDuring the last few months, WECC and Hydro-Québec have raised various concerns about the methods by which NERC allocates costs to the Regional Councils. In January, the Board of Trustees’ newly formed Funding Issues Task Force (see February 8, 2005 Board of Trustees meeting agenda item 18b for more details) expanded the role of the Cost Allocation Subcommittee to include consideration of budget assessment as well as cost allocation issues, and give the subcommittee authority to request subject matter input from other NERC committees as needed to address issues raised within the business plan and budget process. A copy of the scope of the revised Budget Assessment and Cost Allocation Subcommittee (BACAS1) is attached for information.

Following the board meeting, BACAS Chairman Ed Schwerdt wrote the standing committees (letter attached) requesting time to allow representatives from WECC and Hydro-Québec TransÉnergie to present expanded justification for the concerns they submitted.

b. 2005 and 2006 Work Plans

ActionDiscussion

AttachmentOperating Committee 2005 Work Plan (updated January 2005)

BackgroundOn March 15, the Operating Committee and subcommittee officers plus NAESB subcommittee officers will be reviewing the Operating Committee’s 2005 work plan and begin to frame out our activities for 2006. We’ll provide a brief summary for the committee.

1 Secretary’s note: It’s best that one not try to pronounce this acronym.

c. Committee Membership Nominations for 2005–2007

ActionNone

Later this month, the NERC staff will be requesting nominations for those standing committee members whose membership expires on June 30, 2005. The committees’ nomination task forces will coordinate their candidate slates before submitting the names to the Board of Trustees. This class of members will serve terms from July 1, 2005 through June 30, 2007.

Item 6. NERC/NAESB Coordination Items

a. NERC/NAESB TLR Subcommittee

ActionDiscussion

The subcommittee does not formally report to any particular NERC or NAESB group, and the Operating Committee should discuss the group’s goals and objectives and consider recommending changes as necessary.

A representative of the NERC/NAESB TLR Subcommittee (TLR Subcommittee) will provide an overview of recent subcommittee activities and review the subcommittee’s goals and objectives.

Note: the OC will address a resolution from this subcommittee in agenda Item 18.

BackgroundThis subcommittee provides a very important coordination function between NERC and NAESB, and will help ensure that the reliability standards and business practices associated with the TLR Procedure are coordinated before they are submitted to the Joint Interface Committee, and remain coordinated during the NERC and NAESB standards development processes.

The TLR Subcommittee was formed with the primary purpose of reviewing the current NERC Transmission Loading Relief Procedure (Attachment 1 to Standard IRO-006-0 (Reliability Coordinator — Transmission Loading Relief)) and identifying those sections that deal with reliability standards and those sections that are business practices.

NAESB is hosting all meetings of the TLR Subcommittee at its offices in Houston. All meeting materials (agendas, minutes, presentations) are posted at http://www.naesb.org/weq/weq_bps.asp.

The TLR Subcommittee developed a project plan that identified the following goals and objectives:

Goals1. Develop a list of reliability coordinator procedures for invoking an Interconnection-wide

congestion management process. This list will be based on the specifications of the current pro forma tariff.

2. Develop a list of complementary business practices for invoking an Interconnection-wide congestion management process. This list will be based on the specifications of the current pro forma tariff.

3. Provide advice to the respective NERC and NAESB subcommittees as they develop their standards.

4. Provide recommendations to NERC and NAESB on managing the tools and services that support the TLR Procedure.

5. Accomplish, at minimum, objectives 1–4 by year-end of 2005.

ExclusionsThe TLR Subcommittee will not address the WECC and ERCOT congestion management procedures, unless requested by WECC or ERCOT, respectively.

Objectives1. Review the current NERC Transmission Loading Relief Procedure and identify those sections

that deal with reliability standards and those sections that are business practices.

2. Based upon objective 1, draft lists of NERC reliability requirements and NAESB business practices, including the necessary interrelationships and references that could be used to develop standards to replace the current NERC Transmission Loading Relief Procedure.

3. Provide advice to the Operating Reliability Subcommittee and Business Practices Subcommittee as they draft their standards.

4. Through the NERC and NAESB staffs, Ddetermine the regulatory process for replacing the current Transmission Loading Relief Procedures (i.e., retiring TLR Version 0) with the new NAESB business practices and new NERC reliability standards. This may require discussions with the Federal Energy Regulatory Commission staff.

5. Identify and report potential impacts associated with the maintenance and cost of the Interchange Distribution Calculator and E-Tag functional requirements as a result of this process.

6. Review current Alliant and Entergy requests for using a 3% curtailment threshold for certain flowgates and consider how to deal with similar requests from other transmission service providers.

7. Review and recommend the disposition of TLR Requirement 1.6.5 (and others) of Attachment 1 as it relates to crediting mechanisms for redispatch performed prior to TLR.

8. Serve as technical advisors to the IDC Option 3 project management team. Review and, as necessary, develop business cases associated with the implementation of IDC granularity Options 1 and 3.

9. Prepare progress reports for the NERC Operating Committee and NAESB WEQ Executive Committee.

10. Develop a subcommittee timeline.

b. NAESB Version 0 Standards

ActionDiscussion

BackgroundOn January 18, 2005, the North American Energy Standards Board filed with the Federal Energy Regulatory Commission its Report for NAESB Wholesale Electric Business Practices, Docket No. RM05-5-000. This report included the following NAESB business practices:

Note: The NERC staff is suggesting the following changes to the objectives of this subcommittee.

This should be accomplished through the general counsels of the two organizations.

To accommodate the IDC Option 3 project structure.

Business Practice Explanation Responsible Entities

1. Coordinate interchange Request for interchange transaction.

Purchasing-Selling Entity

Balancing Authority

2. Area Control Error (“ACE”) equation special cases

Business practices associated with implementing dynamic schedules and pseudo-ties.

Balancing Authority

3. Manual time error correction Fast- and slow-time error limits for each Interconnection.

Balancing Authority

Reliability Coordinator

4. Inadvertent interchange payback Business practice by which balancing authorities repay inadvertent interchange.

Balancing Authority

c. OASIS Conference

ActionDiscussion

The Operating Committee may want to formally recognize the importance of the upcoming OASIS conference and encourage industry participation. The results of that conference may influence the future direction of OASIS.

AttachmentOASIS Conference Agenda

BackgroundA joint NERC/NAESB conference will be held on Tuesday, March 29, 2005 at the FERC offices in Washington, D.C., to discuss the future of Open Access Same-Time Information System (OASIS). The purpose of the conference is to determine what standards and tools are needed to facilitate the exchange of wholesale electric commodities and to provide informal input to FERC regarding the needs of the industry. Members of the industry will give presentations on future industry requirements and OASIS, as well as participate in an open discussion on the goals and objectives of OASIS II. In addition, other related E-scheduling industry initiatives will be reviewed and discussed. Work papers for this meeting are posted on the NAESB website at http://www.naesb.org/weq/weq_ess_oasis_2.asp

d. Energy Day

ActionDiscussion

BackgroundNAESB is considering two business practices that it has grouped under the subject of “Energy Day:”

Business Practice Explanation

1. R04016. Standard energy day. A standard energy day that would apply to both the natural gas and electric industries. Request that the energy day be standardized as midnight-to-midnight central time.

NAESB has set this business practice aside for now.

2. R04021. Daily operational communications between pipelines and power plants.

Develop standards for the daily operational communications between pipelines and power plants. These communications standards would include anticipated power generation fuel requirements for the upcoming day as well as notification anytime plans change. Likewise standards for pipeline communications for any operating problems that might hinder power plants from receiving required contractual quantities when needed would be developed.

The NERC staff is working with the Interstate Natural Gas Association of America to investigate the merits of establishing a working relationship between the pipeline companies and NERC reliability coordinators.

Item 7. Reports from Other CommitteesGlenn Ross will summarize the actions of the Planning Committee following its meeting.

Item 8. Operator Training

a. Operator Training Program

ActionDiscussion

NERC Operator Training ProgramScheduled for implementation later this year, the NERC training program will institute new operator training standards and accreditation requirements for training program providers. It will also provide a more complete foundation for NERC’s operator certification program.

The table below lists several important milestones that we have completed since the last Operating Committee meeting. The following pages provide additional information on several topics for the committee’s review.

Task Purpose

Received 113 nominations of “excellent” system operators to interview (December 2004).

Learn how system operators achieve excellence. For example, discuss training opportunities, corporate culture, innate abilities, and so forth.

Submitted training standard Standards Authorization Request (December 2004).

Establish minimum requirements for system operator training and training programs.

Selected study panel (January 6, 2005) based on nominations from industry. First meeting will be March 2-3, 2005.

Review FERC training study survey results.

Conduct on-site interviews to learn about training program best practices.

Interview system operators nominated for their excellence.

Visited U.S. Navy Human Performance Center (January 20, 2005).

Provide input for NERC’s human performance study.

First meeting of NERC study panel (March 2–3, 2005)

Discuss operator interview procedures and training program site visits.

Job TaskAnalysis

TrainingProgram

CertificationProgram

TrainingStandards

Formally Considers

Informally Considers

Job TaskAnalysis

TrainingProgram

CertificationProgram

TrainingStandards

Formally Considers

Informally Considers

Task Force Recommendation 19 – Improve near-term and long-term training and certification requirements for operators, reliability coordinators, and operator support staff.

NERC Study PanelNERC has assembled an expert panel of system operators with considerable training experience who will be visiting utilities to interview the system operators who were nominated for their “excellence,” and review a number of utility training programs and facilities. (Please see the following pages for the study panel roster.) We expect to use the information from the FERC training study to help decide which organizations to visit.

Human Performance StudyThe U.S. Navy recently established a Human Performance Center (HPC) (http://www.hpc.navy.mil/) under the leadership of Captain Matthew Peters. Capt. Peters is on the FERC operator training study panel, and met with the NERC project management team, two NERC study panel members, and the FERC contractor (Performance Consulting Services) on January 20 in Virginia Beach.

The information we learned at the Navy’s HPC, plus our interviews with system operators, will help NERC decide how to conduct a human performance study, one of the tasks associated with the NERC training program.

FERC Training StudyOn December 29, 2004, the Federal Energy Regulatory Commission distributed a “Survey on Operator Training Practices” to approximately 150 organizations to “…provide the Commission with valuable information regarding operator training problems that could prevent line outages or improve grid reliability so that we can report to Congress on actions that could be taken to reduce the potential of operator-caused problems.” The survey is due to the Commission by January 31, and the contractor expects initial results will be available by the end of March. We anticipate using that information to help us select organizations to interview.

Training StandardsThe NERC training program’s foundation will be a set of standards that we are now working on. The Personnel Subcommittee has drafted a Standards Authorization Request (http://www.nerc.com/~filez/standards/System-Personnel-Training.html) on which comments were due January 7, 2005. These standards will replace those in the new NERC reliability standards, which are not

comprehensive enough on which to base a training program.

NERC Operator Certification ProgramThe NERC System Operator Certification Program, established in 1998, ensures that power system operators have the knowledge necessary to meet minimum NERC requirements. The program’ centerpiece is an examination that recognizes those individuals who demonstrate the

required knowledge related to the NERC operating policies and basic principles of interconnected system operations. System operators who pass this examination are awarded a certificate that is valid for five years, after which the operator must take the examination again to be recertified. (NERC updates the examination questions every few years.)

Job TaskAnalysis

TrainingProgram

CertificationProgram

TrainingStandards

Formally Considers

Informally Considers

Job TaskAnalysis

TrainingProgram

CertificationProgram

TrainingStandards

Formally Considers

Informally Considers

The Roles of Continuing Education and the Training ProgramAs the first wave of system operators approached the end of their first five-year certification period, NERC began to receive many requests for an alternative to re-testing as a way to renew the operators’ credentials. Among those options suggested was a requirement for attending continuing education classes. This was perceived as less burdensome than preparing for the examination, and, more importantly, had the benefit of providing additional training for the system operator. (Note: the Operating Committee will be asked to approve an update to the Continuing Education Criteria manual in the next agenda item.)

The Personnel Certification Governance Committee (PGCG), which oversees the NERC certification program, agrees with the philosophy of requiring continuing education for system operators. The PCGC is now revising the certification program to incorporate continuing education requirements. NERC’s continuing education program, in place since January 2004, provides a good source to meet those education needs. Finally, the NERC Training Program will establish the curriculum standards upon which the certification program is based, and help training providers select courses to offer.

Implementing Changes to NERC’s Certification ProgramAs the PCGC ties together the parts and pieces for NERC’s new certification program, it must ensure that NERC follows the “good practices” of the National Commission for Certifying Agencies (NCCA) and the National Organization for Competency Assurance (NOCA). The PCGC is establishing the minimum number of hours of continuing education required for re-certification, overseeing the Examination Working Group as it updates the exam questions, and setting up the necessary recordkeeping protocols. Organizations that must comply with NERC standards for operator certification often require their system operators to be NERC-certified as a condition of employment. Therefore, the recordkeeping and verification roles that the PCGC and NERC staff play are vitally important to the success of the certification program and the careers of many system operators. This means that NERC will need to carefully track and verify the continuing education hours that more than 5,000 system operators earn from over 100 NERC-approved training providers every three years.

The PCGC is developing a project plan that will list its goals and objectives as the caretaker of the certification program. This plan will include the tools and staff resource needs and their attendant costs, which the PCGC intends to cover through the certification and recertification fees as well as the continuing education training provider registration charges. It will bring this plan to the NERC Board of Trustees in May.

NERC Training Study Panel RosterMember Information

Nancy Bellows, AGC, Reliability and Transmission Switching Manager, WAPA, Rocky Mountain Region, Loveland, Co.

WECC

Manager of AGC and Transmission Switching control center for the Rocky Mountain region and oversee the real-time operations of the WACM control area, supervisor of their dispatcher training program. Previously, Nancy served at WAPA’s Electric Power Training Center as a dispatch trainer, where she helped design, develop, and deliver training classes for power system operators. Nancy is a NERC-certified system operator.

Patrick Budler, Customer Service and Delivery Training Supervisor, Nebraska Public Power District, Doniphan, NE

MAPP

Customer Service and Delivery Training Supervisor for NPPD. Pat has over 14 years in power system operations as a transmission substation supervisor, system operator, and training specialist before becoming the training supervisor. Pat is a member of the NERC Continuing Education Review Panel (CERP). He has served on the MAPP System Operator Training Working Group, and is current vice chair of the EPRI Power Safety and Reliability Switching Committee. Pat was previously a NERC-certified system operator.

Richard Ellison, Senior System Relief Dispatcher, Bonneville Power Administration, Vancouver, WA

WECC

Senior System Relief Dispatcher for BPA he is presently assigned as the interim manager for BPA Dittmer Dispatching. His duties include dispatch scheduling, rating official for assistant dispatchers, signing authority for dispatcher Standing Orders. Richard served on the NERC Job Analysis Committee that helped develop the NERC system operator job task analysis regarding certification, and been a member of the Item Writing Working Groups for both the WECC and NERC, which help develop test questions for both certification programs.

James Fee, Power System Operator, Sacramento Municipal Utility District, Sacramento, CA

WECC

Power System Operator for SMUD, whose duties include managing the SMUD control area, transmission system, and generating facilities. Prior to joining SMUD, Jim was an operations trainer, and operating-in-training program manager at the California ISO, where he was responsible for the design, development and delivery for the CAISO’s OIT program and continuous education program for system operators. Jim has over 20 years in power system operations and training. Jim started his career at Pacific Gas & Electric Company, working in transmission and distribution centers, and eventually in the system dispatcher’s office. Jim is also a NERC-certified system operator.

Kent Grammer, Operations Training Coordinator, ERCOT, Taylor, TX

ERCOT

Training coordinator for ERCOT. Kent has a strong background in system operations and training development. He is a member of the Personnel Subcommittee.

Donald Harrell, Senior Analyst, Training Coordinator, Entergy Services, Inc., Pine Bluff, AR

SPP

Training coordinator for Entergy (Generation Operations). In his capacity, Donnie is responsible for planning and developing training programs for system operators. He is a member of the NERC Personnel Subcommittee and the Training Resources Working Group. Donnie has over 25 years in system operations, including transmission, generation, and marketing. Donnie is also a NERC-certified system operator.

Neil Lindgren, Operations Coordinator, System Operations, Otter Tail Power Co., Fergus Falls, MN

MAPP

Operations Coordinator for NPPD. Neil has several years experience in generation and transmission operations. In addition, Neil has experience in the design, development, and delivery of training program for system operators. He currently administers the continuing education program for NPPD, and is the current chair of the MAPP/MISO System Operator Training Working Group. He helps design and delivers training for MISO members. Neil is also a NERC-certified system operator.

Member Information

Rémy Bouchard, Transmission Operator, Hydro-Québec TransÉnergie, Rosémere, Québec

NPCC

Transmission Operator for TransÉnergie and has over 30 years experience in system operations. In his capacity with TransÉnergie, he coordinates the control of the transmission system, generation production and security assessment for TransÉnergie’s control area. In addition, Rémy assists with the system operator trainee program and provides practical job-related training. Rémy is also a NERC-certified system operator.

Earl Shockley, System Operator, Trainer, Tennessee Valley Authority, Chattanooga, TN

SERC

System operator for TVA. Earl has been a shift supervisor, training instructor, load coordinator, and reliability coordinator. Earl has helped in the design, development, and delivery of training in electrical apprenticeship programs. He has help developed system operator training simulator, electrical safety programs. Earl is also a NERC-certified system operator.

Don Urban, Power Director, PJM, Greensburg, PA

MAAC

Power Director for PJM. Don has over 30 years experience in power system operations in transmission, power plant operations, and as a training consultant. As a training consultant, He designed, developed, and delivered training program for power plant operators, technicians, and system operators. Don is also a NERC-certified system operator.

b. Continuing Education Program

ActionApprove revisions to the Continuing Education program criteria manual.

Attachment“NERC Continuing Education Program Criteria For Approving and Granting NERC Recognition to Qualified CE Program Providers and Learning Activities”, Version 2.7.3.

BackgroundThe Personnel Subcommittee (PS) is the governing body for the NERC continuing education program. As part of its duties, the PS continually reviews the program to determine its effectiveness, and to ascertain if program changes are needed to meet the needs of NERC and training providers. The PS maintains a track-change page in the administrative manual.

In June 2004, the NERC Board of Trustees approved the implementation of the NERC CE program, and approved the administrative manual, (version 2.7.0). The PS, since that date, has made several minor changes to the manual. The changes correct typographical errors, or add clarity to sections of the manual. The current version of the manual is 2.7.3.

The PS is asking the OC to approve the current version (2.7.3) of the administrative manual. The PS, after consulting with NERC staff, believes that the changes between version 2.7.0 and 2.7.3 are minor changes and do not require board approval. The PS will post the revised manual once approved.

Summary of changes: Section III – Criteria for Approval of CE Providers and Training Activities

o Clarified the number of continuing education review panel (CERP) members that are allowed

Appendix A

o Added a flow chart to show the CE Provider renewal process

Manual page numbering

o Corrected a problem with page numbering from the original manual

CE summary

o Added language to define a CE hour to include at least 50-minutes of organized learning activities

Criteria for CE program measurement

o Added language to Criterion P12 to better define the calculation of a CE hour

Administrative manual changes

o Added a change management page to the CE manual

Item 9. “Best Practices”

ActionAgree on the definition and applicability of “best practices.”

At this meeting, the Operating Committee and Planning Committee will discuss the concept of “best practices,” how NERC should determine what they are, and the role they play in our reference documents, guidelines, standards, and compliance and audit programs.

(Note: the secretary has provided a suggested action at the end of this background document.)

AttachmentNetwork Reliability and Interoperability Council paper on “Best Practices”

BackgroundSome of the recommendations from the U.S.-Canada Power System Outage Task Force suggested that NERC develop lists of “best practices” to address the need for operator tools and information technology security procedures. The Operating Committee now has a Real-time Tools Best Practices Task Force, and the NERC Training Program is studying “best practices” in training programs. The readiness audits that NERC has conducted have produced lists of what were originally called best practices that we now refer to as “examples of excellence2.”

So, what are “best practices?” Are they standards? Guidelines? Recommendations? Or just things to consider? Do best practices need to meet a particular rubric, or are they subjective?

To help us start this discussion, we turn to another council — the Network Reliability and Interoperability Council — for its definitions and thoughts on what constitutes “best practices.” The NRIC mission statement is in the text box on the right, and the NRIC’s paper on best practices is attached.

Note two key passages from this paper (emphasis added):

“NRIC Best Practices are the most authoritative list of such guidance for the communications industry. They result from broad industry cooperation that engages vast expertise and considerable voluntary resources. The primary objective of Best Practices is to provide guidance from assembled industry expertise and experience. This guidance is highly valuable because it is not easy to duplicate on an individual company basis.”

And

“Mandated implementation of these Best Practices is not consistent with their intent. The appropriate application of these Best Practices can only be done by individuals with sufficient competence to understand them. Although the Best Practices are written to be easily understood, their meaning is often

2 NERC originally used the term “best practices” in its readiness audit reports, but for good reasons, we decided to change that term. We briefly used “noteworthy practices” in place of best practices. We’ve settled on “examples of excellence” for the readiness audits, leaving the committees and industry to work through what ought to be considered “best practices.”

NRIC Mission

“Partner with the Federal Communications Commission, the communications industry and public safety to facilitate enhancement of emergency communications networks, homeland security, and best practices across the burgeoning telecommunications industry.”

www.nric.org

not apparent to those lacking experience and/or expertise in the specific job functions related to the practice. Appropriate application requires understanding of the Best Practice impact on systems, processes, organizations, networks, subscribers, business operations, complex cost issues and other considerations. With these important considerations regarding intended use, the industry is concerned that government authorities may inappropriately impose these as regulations or court orders.”

In summary, based on the NRIC’s definition, best practices are:

Subjective

Intended to provide guidance

Developed by experts for experts

Not to be mandated by government authorities

Examples of Possible “Best Practices”Here’s a partial list of what the NERC audit teams called “examples of excellence” that could become “best practices” after appropriate review.

Yearly operator re-certification

“Surprise” emergency drills

Reactive power monitoring zones

Reactive resource testing

Calculation of “n-2” contingencies

Operator supervisor certification

Mutual backup agreement to telecommunications providers

Strobe light and countdown timer on DCS event

ACE display for all control areas

Blackstart tests

How would we identify a “Best Practice”The technical committees are well suited to judge whether an example of excellence should be elevated to a best practice. The committees could base their decisions on recommendations from their various subcommittees.

What do we do with “best practices?”Once NERC has identified best practices, what do we do with them? One possibility is to publicly post these practices along with contact information for those seeking additional information. NERC could recommend that organizations review these best practice lists, but NERC would not audit anyone for implementation. Furthermore, NERC would clearly explain that best practices are not standards and neither NERC, its members, nor the regulatory agencies should expect compliance with any best practices.

Secretary’s Suggested ActionFirst, consider the procedures that we do to plan and operate the Interconnections as belonging to one of three categories or levels:

1. Examples of excellence that NERC lists on its website from its readiness audits for information and discussion,

2. Best practices that are determined by NERC’s technical committees and their subcommittees, but for which compliance is voluntary, and

3. Reliability standards that are formally approved through NERC’s standards development process, and for which compliance is mandatory.

Then agree on the following:

Request that the subcommittees regularly review the “examples of excellence” that NERC will post from its readiness audits and decide whether to:

1. Add examples of excellence to a reference document, or

2. Recommend to the Operating Committee that certain examples of excellence be elevated to “best practices,” or

3. Prepare a Standards Authorization Request that would elevate an example of excellence or best practice to a NERC standard.

Item 10. FERC Reactive Power Report

ActionDiscussion

The Resources Subcommittee and Transmission Subcommittee are reviewing the report and will provide their answers to the questions that the FERC staff has posed.

AttachmentFERC staff report, “Principles for Efficient and Reliable Reactive Power Supply and Consumption,” February 4, 2005. – Executive Summary (For complete report, visit http://www.ferc.gov/EventCalendar/Files/20050204114044-02-04-05-reactive-power.pdf )

BackgroundThe Federal Energy Regulatory Commission is requesting comments on its report, “Principles for Efficient and Reliable Reactive Power Supply and Consumption,” by April 4, 2005.

The NERC staff has reviewed this report and has been discussing some of the technical issues with the FERC staff on an informal basis. These have centered on the concepts of:

1. Overall role that reactive power plays in the operations of an ac power system.

2. “Local” nature of reactive power delivery.

3. Differences between static and dynamic reactive power supplies.

4. Need for market rules that encourage development of reactive power supply and deployment of reactive power reserves when needed to support transmission voltage.

The Operating Committee may want the Transmission Subcommittee and Resources Subcommittee to review the Commission’s paper and provide their comments. (Given the short deadline for comments, these subcommittees may have already begun this review.)

NERC Recommendation 10 – The Operating Committee shall within one year evaluate the real-time operating tools necessary for reliable operation and reliability coordination, including backup capabilities. The Operating Committee is directed to report both minimum acceptable capabilities for critical reliability functions and a guide of best practices.

Task Force Recommendation 22 - Evaluate and Adopt Real-Time Tools for Operators and Reliability Coordinators

Item 11. Blackout Recommendations: Real-Time OperationsThe Operating Committee needs to discuss the implementation plans for the following five sets of recommendations related to Operations – Real Time:

Operator “Tools”

Communications – Hotline

Definitions of Operating Conditions

TLR Use

a. Operator “Tools”

ActionDiscussion

AttachmentExcerpt of draft state estimator survey of best practices

Status The Real-Time Tools Best Practices Task Force will post its

web-based survey in April.

Final report to the Operating Committee in September 2005.

The Real-Time Tools Best Practices Task Force continues its effort to develop an industry survey of best practices. The RTBPTF expects to present its preliminary report to the OC June 2005, with a final report in September. That report will cover the following topics:

1. Specify required tools, including performance requirements, to support NERC standards for situational awareness.

2. Specify best practices, including performance requirements, to support NERC standards for situational awareness.

3. Draft SARs as needed for standards.

4. Define expectations for:

a. Management education

b. Operator input

c. User-vendor coordination

5. Assemble a compendium of promising tools in the industry.

Background

From July 2004 OC meeting agendaNERC Requirement 10 of February 10, 2004, directs the Operating Committee to evaluate within one year the real-time operating tools necessary for reliability operation and reliability coordination, including backup capabilities. The committee’s report is to address both minimum acceptable capabilities for

critical reliability functions and a guide to best practices. The U.S.-Canada Power System Outage Task Force supported these requirements strongly. It recommends that NERC require the committee to:

1. Give particular attention in its report to the development of guidance to control areas and reliability coordinators on the use of automated wide-area situation visualization display systems and the integrity of data used in those systems.

2. Prepare its report in consultation with FERC, appropriate authorities in Canada, DOE, and the Regional Councils. The report should also inform actions by FERC and Canadian government agencies to establish minimum functional requirements for control area operators and reliability coordinators.

The task force also recommends that FERC, DHS, and appropriate authorities in Canada should require annual independent testing and certification of industry EMS and SCADA systems to ensure that they meet the minimum requirements envisioned in Recommendation 3.

The Operating Reliability Subcommittee has established a Real-time Tools Best Practices Task Force (RTBPTF) to identify the best practices currently employed for building and maintaining real-time network models and for performing state estimation and real-time contingency analysis. The ultimate goal of the task force will be to recommend specific, auditable requirements for inclusion in new reliability standards for real-time network modeling and network analysis tools. An interim goal will be to develop guidelines for minimally acceptable capabilities for these critical reliability tools.

The Operating Committee approved the scope of this task force at its July 2004 meeting.

b. Communications – Hotline

Status New hotline conference system implemented as of February 25,

2005, which completes the communications system upgrade.

Reliability coordinators are still testing the new hotline procedures.

Operating Reliability Subcommittee reviewing telecommunications within RC footprints.

The hotline procedure is still in field test and a final report will be presented to the OC in June 2005. The OC does not need to take action on these procedures.

The NERC conference bridge is now in place and the reliability coordinators tested the conference bridge for hotline calls during the week of February 14, 2005, with final implementation on February 25.

The subcommittee continues its review of telecommunications within a reliability coordinator’s footprint, e.g., RC to balancing authorities and transmission operators.

Background

From July 2004 OC meeting agenda1. Procedures for operator and reliability coordinator communications during emergencies. The

Reliability Coordinator Working Group addressed Recommendation 9B by developing enhanced NERC Hotline Procedures. The RCWG agreed to implement the draft procedures on an interim basis, and will re-assess their effectiveness and completeness at its September 2004 meeting.

NERC Recommendation 9b – Evaluate and improve the tools and procedures for operator and reliability coordinator communications during emergencies.

Task Force Recommendation 26.A – Tighten communications protocols and upgrade Communications Systems

Task Force Recommendation 31 – TLR Use. Clarify that the transmission loading relief (TLR) process should not be used in situations involving an actual violation of an Operating Security Limit. Streamline the TLR process.

Task Force Recommendation 20 – Definitions of Operating Conditions. Establish clear definitions for normal, alert and emergency operational system conditions.

NERC Recommendation 9b – Evaluate and improve the tools and procedures for operator and reliability coordinator communications during emergencies.

2. Communications protocols and systems. To address task force Recommendation 26A, NERC is establishing a telephone conference bridge that will serve as the reliability coordinator hotline. This bridge will also provide greater flexibility than the current telephone-company-provided conference service.

c. Definitions of Operating Conditions

Status In progress.

The Operating Reliability Subcommittee discussed this recommendation further at its February 9–10, 2005 meeting. The subcommittee formed a task group to address the recommendation requiring the definition of the terms “normal”, “alert”, and “emergency” conditions. The subcommittee believes that a more consistent application of these terms will enhance reliability coordinator to reliability coordinator communications, especially when applied to the reliability coordinator Information System. The Reliability Coordinator Working Group is working on improvements to the RCIS that may include these definitions.

d. TLR Use

Status Complete.

The Operating Reliability Subcommittee will ask the NERC/NAESB TLR Subcommittee to consider “streamlining the TLR process” as one of its goals.

BackgroundOn July 21–22, 2004, the Operating Committee agreed that Policy 9F.1 (Standard IRO-005-0, requirements 3 and 5) provides the reliability coordinators with the latitude to mitigate System Operating Limit and Interconnected Reliability Operating Limit violations.

Item 12. Blackout Recommendations: Operations Planning

a. Operations Planning – General

Status Not started.

The OC formed the Operations Planning Task Force with representatives from California ISO, ERCOT, and SERC at its November 2004 meeting. The task force has not yet started work on its assignment primarily because of the lack of NERC staff resources. We’ll start working on this assignment as soon as others are finished.

b. Identification of “Critical Facilities”

Status In progress.

The U.S.-Canada Power System Outage Task Force recommendation was aimed at making sure the reliability coordinators were monitoring the critical elements of the transmission system. The Operating Reliability Subcommittee, while continuing to discuss this issue, has concluded that control areas (transmission operators) and reliability coordinators determine “critical facilities” based on NERC's definitions of operating limits, including System Operating Limit and Interconnected Reliability Operating Limit. In other words, the critical facilities should be defined in the context of the SOL and IROL determination, not just as a list of facilities. The reliability coordinators are also addressing this issue in response to the following standards:

1. Standard IRO-001-0 (RC Responsibilities and Authorities) Requirement 7, which states:

The reliability coordinator shall have clear, comprehensive coordination agreements with adjacent reliability coordinators to ensure that System Operating Limit or Interconnection Reliability Operating Limit violation mitigation requiring actions in adjacent reliability coordinator areas are coordinated.

2. Standard IRO-002-0 (RC Facilities) Requirement 2, which states:

Each reliability coordinator shall determine the data requirements to support its reliability coordination tasks and shall request such data from its Transmission Operators, Balancing Authorities, Transmission Owners, Generation Owners, Generation Operators, and Load-Serving Entities, or adjacent Reliability Coordinators.

NERC Recommendation 13a – The Operating Committee shall evaluate operations planning and operating criteria and recommend revisions in a report to the board within one year.

Task Force Recommendation 30.A – Identification of Operationally Critical Facilities. NERC should work with the control areas and Reliability Coordinators to clarify the criteria for identifying critical facilities whose operational status can affect the reliability of neighboring areas.

c. Communications – Line Outage Information

Status Complete.

The reliability coordinators are updating the SDX hourly, and outage information reported via the SDX is automatically “ported” to the Reliability Coordinator Information System. The IDCWG’s SDX Self-directed Work Team implemented a “common names” feature within the SDX. The feature requires the population of the SDX database with the facility common names, which remains to be completed by all reliability coordinators.

The Operating Reliability Subcommittee and the Reliability Coordinator Working Group believe that these NERC and task force recommendations are complete.

Background

From July 2004 OC meeting agendaThe IDC Working Group and its System Data Exchange (SDX) Self-Directed Work Team revised the Reliability Coordinator Reference Document per the request of the Operating Reliability Subcommittee. Changes to the reference document reflect:

1. Hourly SDX updates are mandatory for all reliability coordinators and all control areas. This replaces daily updates.

2. SDX data submittal requirement for all status changes of transmission facilities (100 kV and above) and generators (20 MW and above). This expands the reporting requirements.

3. Forced outages of transmission facilities (230 kV and above) and generators (300 MW and above) will be automatically posted to the Reliability Coordinator Information System (RCIS) by messaging from the SDX system to the RCIS.

The Operating Committee approved this change at its March 23–25, 2004 meeting.

On May 17, 2004, additional functionality was added to the NERC RCIS and SDX applications to allow for the following to occur for forced outages that are submitted to the NERC SDX application:

Any SDX outage that is submitted with the “F” – Forced status AND meets the following criteria will be automatically sent to the NERC RCIS as an outage message:

Forced outage start time is in the past or within the next six hours, and Forced outage is a transmission line that is 230 kV or above, or Forced outage is a generator that has a capability of 300 MW or above.

Recommendation 9c – Evaluate and improve the tools and procedures for the timely exchange of outage information among control areas and reliability coordinators.

Task Force Recommendation 30B – Information on Unplanned Outages

Item 13. Blackout Recommendations: Restoration

Status In progress.

BackgroundThe Operating Reliability Subcommittee and Reliability Coordinator Working Group have discussed the restoration of the power system on two occasions, and the sense of both groups is that the restoration was very successful. Also, the Ontario Independent Electric System Operator explained how they managed the control room staff during the restoration process, and provided a number of suggestions on the human performance factors of system restoration.

ECAR, NPCC, and MAAC each prepared reports that explained how their system operators restored the bulk electric system in their region after the blackout occurred. In addition, ECAR and NPCC provided a list of recommendations for NERC to consider implementing within each Interconnection. The Operating Reliability Subcommittee will review these recommendations, decide which ones to pursue, and then present its report to the Operating Committee in March.

The following outline melds the NPCC and ECAR recommendations into a single list that the Operating Reliability Subcommittee and Reliability Coordinator Working Group will review at their next meeting:

1. Up-to-date restoration criteria and guides. Each regional council, regional transmission organization, or independent system operator, should ensure their restoration criteria and guides are up to date and include the lessons learned from the August 14, 2003 blackout. (And 1996 blackout in the Western Interconnection – DMB.)

2. Agreements and authorities.

a. Ensure that Transmission Operators and Generators have agreements in place for mitigating system emergencies and conducting restoration drills.

b. Ensure that system operators have the authority to take any action required, including load shedding, to comply with NERC standards.

c. Ensure that system operators understand their roles and responsibilities, and have adequate training to properly carry out those roles and responsibilities.

3. Voice communications

a. Review adequacy of voice communications following a blackout or other system emergency.

b. Establish an “open” conference call of reliability coordinators, and, more locally, transmission operators, to ensure close coordination during restoration.

c. Manage incoming phone calls, separating those calls seeking information from calls to operating personnel engaged in the restoration. Furthermore, prioritize communications and disseminate critical information during restoration.

d. Implement FERC emergency standards of conduct to allow free exchange of information during the emergency and restoration.

NERC Recommendation 11a – The Operating Committee, working in conjunction with the Planning Committee, NPCC, ECAR, and PJM, shall evaluate the black start and system restoration performance following the outage of August 14, and within one year report to the NERC board the results of that evaluation with recommendations for improvement.

Task Force Recommendation 29.A – System Restoration Lessons Learned. Evaluate and disseminate lessons learned during system restoration. Require the Planning Committee’s review to include consultation with appropriate stakeholder organizations in all areas that were blacked out on August 14.

e. Test backup communications procedures. Ensure that all transmission operators, balancing authorities, and reliability coordinators have adequate backup communications facilities, and that those facilities are tested periodically.

4. Real-time data availability

a. Ensure that reliability coordinators, balancing authorities, and transmission operators review their data supply for critical information that they need for restoration.

b. Ensure the energy management systems can properly buffer and prioritize alarms during a disturbance.

5. Real-time controls to manage demand.

a. Use public appeals to limit load as necessary during restoration.

b. Ensure that load-shedding capability is available to the system operator during restoration.

6. Contingency analysis

a. Each reliability coordinator must have a “wide area” view to more rapidly assess the state of the interconnected bulk electric system following a large-scale system disturbance.

7. Restoration drills.

a. Conduct restoration drills and tabletop exercises at least annually.

b. Review synchronizing procedures (generators and load “islands”) and stabilizing procedures (matching generation and demand in “islands.”)

c. Develop or review procedures for matching voltage and frequency for manually resynchronizing electric islands, and incorporate those procedures in the appropriate regional (RTO, etc.) documents.

d. Review the potential synchronizations made between electrical islands by automatic re-closing and determine if these re-closures are appropriate and consistent with the normal, steady state design intent of the automatic re-closing systems.

i. Review manual synchronizations, and develop methods to avoid manual inadvertent synchronizations in the future.

ii. Results should be incorporated into switching procedures and training.

8. Facilities.

a. Each control area, transmission operator, and reliability coordinator should review the adequacy of the office space and facilities needed to support the additional staffing required during the restoration process following a large-scale blackout.

b. Each control area, transmission operator, and reliability coordinator should contact their local phone providers to ensure they have sufficient fuel for their backup generators the their central offices.

9. Managing interchange, including reloading transactions that had been suspended. Control areas and purchasing-selling entities should review their obligation to correct tags (curtail transactions) when their control area is blacked out.

a. Reliability coordinators should adopt procedures to curtail tags when an area is blacked out and the responsible CA/PSE does not curtail tags.

b. Review and modify tagging procedures in NERC reliability standards, and applicable appendices, during emergency and system restoration periods to add clarity to the responsibilities of the PSEs, CAs, and RCs.

c. Ensure the IDC can be managed during restoration. This includes suspending tag approvals as necessary.

The Planning Committee’s Transmission Issues Subcommittee is working on recommendations regarding the availability of blackstart generators. The NERC staff will coordinate the work of the TIS and ORS to ensure that we properly consider the operations aspects of blackstart generation.

Item 14. Reliability Standards

a. Functional Model – Reliability Standards Coordination

ActionApprove recommendations from the Functional Model – Reliability Standards Coordination Task Force.

Attachment“Recommendations to Facilitate Use of the Functional Model in Reliability Standards,” Functional Model – Reliability Standards Coordination Task Force. [Will be sent separately when available]

Regional Reliability Plans. Based on the outcome of these discussions, Sam Jones may suggest that the Reliability Coordinator Plan Task Force suspend developing the regional reliability plan templates. The Functional Model – Reliability Standards Coordination Task Force may pick up this work instead.

b. Balance Resources and Demand Field Test

ActionApprove phase II field test for proposed standard BAL-007-1, “Balance Resources and Demand.”

Approval means that the Operating Committee is satisfied that the field test is warranted and that it will not jeopardize interconnected systems operation.

Resources Subcommittee member Raymond Vice will lead this discussion. He will cover the salient features of BAL-007-1 and the field test.

AttachmentLetter – Raymond Vice to NERC Roster – “Request for Phase I Field Test Volunteers” (The field test procedure is attached to this letter.)

Letter – Raymond Vice to NERC Roster – “Request for Balance Resources and Demand Standard Phase II Field Test Volunteers” (Field test details attached to this letter)

BackgroundThe field test will validate the standard drafting team’s concepts and the standard metrics. The drafting team completed the Phase I field tests in 2004, and will use that year’s data to calibrate the metrics in preparation for the Phase II field tests. This second phase will involve volunteer balancing authorities operating their systems under this proposed standard.

For the proposed standard and reference document, visit http://www.nerc.com/~filez/standards/Balance-Resources-Demand.html

Item 15. Interconnection Frequency IssuesThis item covers four issues about Interconnection frequency. But first, here are some key terms:

Frequency Error (Hz). The difference between the actual and scheduled frequency. Scheduled frequency is normally 60 Hz. Time error corrections require offsets to scheduled frequency of ± 0.02 Hz. Frequency errors are caused by a mismatch between Interconnection generation and demand. In the figure on the right, the scheduled frequency is 60 Hz, and the frequency error is the difference between 60 Hz and the red trace.

Frequency Deviation (Hz). Any change in frequency between two points in time. Frequency deviations are caused by generation or demand changes. In the figure, the frequency deviation from 20:00 to 24:00 is about 0.11 Hz.

Frequency Response (MW/Hz or MW/0.1 Hz). The ratio of the change in generation or demand to the change in frequency. The event that caused the 0.11 Hz frequency deviation as the sudden loss of 1,550 MW of generation. The frequency response was 13,839 MW/Hz. or 1,384 MW/0.1 Hz.

Frequency Oscillation (sec). A rhythmic change in frequency through time. Oscillations can last minutes or longer. In the figure, one can see a frequency oscillation before and after the generation loss.

a. Frequency Error

ActionDiscuss options for tracing and correcting protracted Interconnection frequency errors.

AttachmentLetter – James Fuhrmann to Mark Fidrych – February 3, 2005 Frequency Error in the Eastern Interconnection

BackgroundAs Mr. Fuhrmann explains in his letter to Mark Fidrych, “On February 3, 2005 at approximately 2100, the Frequency Error on the Eastern Interconnection dipped to 59.91 Hz. On this day and previous days the frequency remained below 59.97 Hz for approximately 10 minutes with no actions being initiated by Reliability Coordinators.” Frequency errors of unknown origin are not unusual. Sometimes they are caused by “backward” schedules, mismatched schedules, or schedules with a missing source or sink (“air” MW).

Southern Control Area - 6 Second Data1/16/2005 1700 CST

-400

-300

-200

-100

0

100

200

300

400

0:00 4:59 9:53 14:47 19:47 24:47 29:48 34:48 39:47 44:41 49:41 54:42 59:42Min:Sec

Meg

awat

ts

59.90

59.91

59.92

59.93

59.94

59.95

59.96

59.97

59.98

59.99

60.00

60.01

60.02

60.03

60.04

60.05

60.06

60.07

60.08

60.09

60.10

Frequency - Hz

ACE Act Freq Sched Freq

59.907 Hz. at 17:23:42

60.019 Hz at 17:21:00 CST

60.003 Hz. at 17:28:12 CST

Secretary’s NoteThere may be another problem. Here’s the former operating policy that Mr. Fuhrmann cites:

9F4. Determining causes of Interconnection frequency error. Any RELIABILITY COORDINATOR noticing an INTERCONNECTION frequency error in excess of 0.03 Hz (Eastern INTERCONNECTION) or 0.05 Hz (Western and ERCOT INTERCONNECTIONS) for more than 20 minutes shall initiate a NERC Hotline conference call, or notification via the Reliability Coordinator Information System, to determine the CONTROL AREA(S) with the energy emergency or control problem.

…and here is the new standard that replaced it:

IRO-005-R11. The Reliability Coordinator shall identify sources of large Area Control Errors that may be contributing to Frequency Error, Time Error, or Inadvertent Interchange and shall discuss corrective actions with the appropriate Balancing Authority. If a Frequency Error, Time Error, or inadvertent problem occurs outside of the Reliability Coordinator Area, the Reliability Coordinator shall initiate a NERC hotline call to discuss the Frequency Error, Time Error, or Inadvertent Interchange with other Reliability Coordinators. The Reliability Coordinator shall direct its Balancing Authority to comply with CPS and DCS.

We’ve lost the 0.03/0.05 Hz and 20 minute “triggers” that would initiate reliability coordinator investigations of a frequency error. (Also, the middle sentence is of questionable merit, but it’s not contributing to this issue.)

The OC may wish to consider requesting the Reliability Coordinator Working Group to develop a procedure for quickly tracing and correcting the source of frequency errors.

b. Frequency Response

ActionDiscussion

Resources Subcommittee Chairman Carl Monroe will lead this discussion. While the Operating Committee does not need to take action on this issue, it does need to be aware of the declining frequency response in the Eastern Interconnection.

BackgroundThe frequency response in the example on the previous page is much lower than normal. In other words, for a given change in generation, the frequency change of the Interconnection was greater than in the past. The nominal frequency response for the Eastern Interconnection is about 3,250 MW/0.1 Hz, but for the event on January 16, it was calculated at about 1,384 MW/0.1 Hz. One reason for this lower response is attributed to the low demand and generation on line at the time. The Operating Committee assigned the Resources Subcommittee to study frequency response, which is why the subcommittee has been interested in establishing a frequency data warehouse. (See next item.)

The Resources Subcommittee has been studying frequency response, and in his recent note to the Resources Subcommittee, subcommittee member Raymond Vice explained that:

“A cursory look at 2004 compared to 2003 seems to indicate that frequency response has declined by 4,156 MW/Hz or about 12.65% from last year. That is only about 36.4% of the 2003 standard deviation, however, and the number of samples is relatively low (12 in 2003 and 16 in 2004), so I’m not particularly convinced that it indicates a “real” trend.

“What’s more interesting is the 49.6% change in Standard Deviation from 2003 to 2004. The standard deviation went from 11,423 MW/Hz. (34.8% of mean) in 2003 to 5,762 MW/Hz. (20.1% of mean) in 2004. This would appear to indicate a considerable decrease in the variability of Eastern Interconnection frequency response from 2003 to 2004. I'm not sure what (if anything) to make of this, but it may be indicative of the shift in generation mix due to the increase in gas prices. This may indicate that that the mix of committed generation remained more stable (probably true, since the cost of gas kept gas turbines from getting into the unit commitment mix as often and thus the mix of coal fired units remained relatively consistent) or that coal fired steam turbines respond more consistently to frequency changes than do gas turbines.”

c. Frequency Analysis

ActionDiscussion

BackgroundAt its October 2004 meeting, the Operating Committee approved the following resolution that assigned the Resources Subcommittee with analyzing the frequency characteristics of all Interconnections:

1. The OC expects the Interconnections (Eastern, Western, ERCOT, and Hydro-Québec) to analyze their frequency to determine if NERC’s balancing standards are “safe and reliable.”

2. The OC understands that the Interconnections’ frequency profiles may be different.

3. The OC expects that these analyses be conducted according to a consistent set of analytical methodologies that the Resources Subcommittee establishes.

4. The OC expects that the Interconnections will maintain this data and cooperate with the Resources Subcommittee’s needs to perform its analyses. The RS members will agree upon a data retention requirement.

At this meeting, Resources Subcommittee Chairman Carl Monroe will explain how the subcommittee is meeting this assignment.

Item 16. EPRI TagNet PresentationThis item provides for a follow-up discussion from Steve Lee’s TagNet presentation at the joint meeting on March 16.

Item 17. Eastern Interconnection-wide Reliability Studies Initiative

ActionThe Operating Committee should consider formally supporting this initiative for the Eastern Interconnection, which will improve Interconnection-wide operations planning.

BackgroundWECC regularly conducts Operating Transfer Capability studies for the upcoming season for the interties in the Western Interconnection. Historically, the Eastern Interconnection regional reliability councils have formed inter-regional groups that conducted pre-seasonal assessments of parts of the Eastern Interconnection. The expansion of the large markets of PJM and MISO across the boundaries of the existing regions in the Eastern Interconnection is necessitating a re-thinking of how inter-regional transmission reliability studies can and should be performed. The large market generation dispatch and changes to transaction patterns require changes in seasonal study base cases used by the interregional study groups. At the same time, real-time study capabilities have made significant advancements in their speed and capabilities, often outstripping the old pre-seasonal study capabilities. It is time to redesign the pre-seasonal studies to keep them meaningful and to augment on-line analysis available from real-time contingency analysis and state estimators.

Bob Cummings will present an outline of a white paper on Interconnection-wide reliability studies that is being prepared by members of the interregional study community.

Item 18. Congestion Management

a. TLR Redispatch Credit

ActionApprove request from PJM and MISO to allow these organizations to implement the process described in the “Determining Redispatch Credit” document.

Secretary’s note: The process is implemented through a change in the IDC algorithms, referred to as Change Orders 154 and 157 in the resolutions below. The Operating Reliability Subcommittee’s executive committee is scheduling a conference call prior to the OC meeting to prepare a recommendation for the committee.

Attachment “Determining Redispatch Credit”

“Report to the OC and ORS on NERC/NAESB TLR Subcommittee Endorsement of PJM Process for Determination of Redispatch Credit”

Background

November 2004 – OC MeetingAt the November 2004 OC meeting, Andy Rodriquez from PJM explained that PJM and MISO wished to be credited for the redispatch they perform ahead of the time at which TLR curtailments are ordered. While the TLR Procedure recognizes that transactions may be protected from curtailment by redispatch, the procedure does not specify the particular manner for determining the amount of relief provided via redispatch.

The Operating Reliability Subcommittee discussed this at its February 9–10, 2005 meeting and, after considerable discussion, approved the following resolution:

“WHEREAS the Operating Reliability Subcommittee has discussed the proposal by MISO and PJM that would allow organizations to receive credit for their proactive and reactive redispatch when in a TLR 3A or 3B by implementation of IDC CO-157, and

“WHEREAS the Operating Reliability Subcommittee believes that the concept of allowing credit for action taken prior to and during the implementation of TLR has merit with the benefits potentially including reduction in the frequency and magnitude of TLR events, quicker relief, and more accurate relief. However, if this concept is not appropriately implemented it may also have unintended consequences that require further evaluation, including but not limited to:

Possible increase in number and magnitude of TLR 5 curtailments,

Possible confusion on appropriate magnitude of TLR 3A and 3B curtailments required,

Coordination of potential additional actions required of RCs and interactions between RCs, and

Ramping considerations on those parties receiving additional curtailments,

And

“WHEREAS the Operating Reliability Subcommittee recognizes that this proposal includes business practices, and

“WHEREAS the NERC/NAESB TLR Subcommittee has been created to coordinate the development of reliability standards and complementary business practices associated with the TLR procedure,

“THEREFORE, the Operating Reliability Subcommittee requests that the NERC/NAESB TLR Subcommittee consider the implementation of the non-firm redispatch credit proposal from a business practice perspective and bring its recommendations to the Operating Reliability Subcommittee for further consideration.”

February 25 – NERC/NAESB TLR Subcommittee meetingOn February 25, the NERC/NAESB TLR Subcommittee considered PJM's request as documented in the attached file titled “Determining Redispatch Credit.” Following its review and revision of this document, the Subcommittee passed the following resolution, which "recommends to the ORS and the Operating Committee that PJM and MISO be allowed to utilize this process as soon as practical through the expedient implementation of IDC Change Orders 157 (Non-firm Redispatch Credit) and 154 (Firm Redispatch Credit)." The subcommittee's complete resolution follows:

“WHEREAS the NERC/NAESB TLR Task Force has reviewed the attached “Determining Redispatch Credit” document, and

“WHEREAS the Task Force believes the process in that document represents an equitable and reliable method for determining the impacts of redispatch prior to entering TLR, and

“WHEREAS the Task Force recognizes that later actions may be taken by NERC, NAESB, or FERC to modify, enhance, or eliminate this process, and

“WHEREAS the NERC Operating Committee, Markets Committee, and Operating Reliability Subcommittee have requested the Task Force to provide a recommendation regarding PJM's and MISO's request to implement this process,

BE IT RESOLVED that the NERC/NAESB TLR Task Force hereby endorses the process described in the "Determining Redispatch Credit" document, and recommends to the ORS and the OC that PJM and MISO be allowed to utilize this process as soon as practical through the expedient implementation of IDC Change Orders 157 (Non-Firm Redispatch Credit) and 154 (Firm Redispatch Credit).”

b. Interchange Distribution Calculator Option 3 Project

ActionDiscussion. The Operating Committee should keep in mind that it may need to take formal action at some point to approve NERC funding for this project.

Larry Kezele will lead this discussion.

Attachments“White Paper on the Future of Congestion Management,” Version 2.1, June 2004, by the IDC Granularity Task Force.

Letter – Ed Schwerdt to Mark Fidrych and Don Benjamin – IDC Option 3 RFP

BackgroundOver the last few years, the Operating Reliability Subcommittee and Reliability Coordinator Working Group have been working on the concepts for the next “generation” of the Interchange Distribution Calculator. A few years ago, they formed an IDC Granularity Task Force that produced a paper (attached) describing three options for improving the accuracy and effectiveness of the IDC.

Status — Option 1In July 2004, the Operating Committee and the Market Committee approved implementation of IDC Granularity Task Force Option 1 by June 1, 2005, and to develop a business plan for Option 3 by September. The IDC vendor developed and evaluated an IDC change order to implement Option 1, and stated that the change order could be implemented by June 1, 2005.

The IDCWG also surveyed transmission providers to determine how the various providers evaluate transmission service requests. The results of that survey indicated that there would not be a significant increase in IDC granularity resulting from the implementation of Option 1.

The Operating Reliability Subcommittee considered the implementation of IDC Change Order 163 (IDC Granularity Enhancements – Option 1) at its February 9–10, 2005 meeting, and approved the following motion:

That due to transmission survey results and inability to implement Option 1 by June 2005, that moving forward with implementation of Option 1 be postponed until fall 2005 at which point a benefit/cost analysis of Option 3 will be available, and then a decision could be made to pursue Option 1 or Option 3.

In other words, it appeared more efficient to bypass Option 1 and proceed directly with Option 3, one of the reasons also being that the regional managers have requested an RFP for the “next generation” of IDC by January 2006 as we’ll discuss next.

Status — Option 3The regional managers have requested expediting the preparation of the business case to implement the IDC Granularity Task Force Option 3 (letter attached). To manage this project, the NERC staff has formed a project management team with technical input from the NERC/NAESB TLR Subcommittee.

Other groups, such as the Operating Reliability Subcommittee, Reliability Coordinator Working Group, and Regional Managers will also have roles to play.

Executive Summary from the IDC Granularity Task Force White Paper (emphasis added)“Experience has shown that the current Transmission Loading Relief (TLR) Procedure often takes a significant amount of time to implement. Further, because the TLR process relies on curtailment of transactions as an ineffective proxy for ordering generation redispatch, significant amounts of transactions have to be interrupted to provide the necessary relief. The events of August 14, 2003, show that the time taken to effect relief on transmission elements can be crucial to the reliability of the system.

“The IDC Granularity Task Force (IDCGTF) feels that the existing IDC will not sufficiently serve the needs of the electric utility industry in the future without a significant overhaul.

“The IDCGTF presents three options for consideration by the electric power industry for the long-term vision of congestion management.

“Option 1 would modify the IDC to evaluate the impacts of interchange transactions using the same level of granularity, at least, that is used by Transmission Providers to evaluate transmission service requests. Option 1 does not address all of the problems facing the IDC, such as the need to incorporate comparable treatment of counter-flows on Flowgates. But the IDCGTF does believe Option 1 provides some improvement in granularity and could be implemented fairly quickly. Option 1 could be implemented as a stand-alone change or as an intermediate step toward Options 2 or 3.

“Option 2 continues to utilize the tagging and modeling granularity described in Option 1, but changes how responsibilities to achieve relief are calculated and assigned. Internal and External Relief Responsibilities (IRR/ERR) would be calculated, as detailed in Appendix A of this paper, for each Balancing Authority (BA) or Control Area (CA). Under Option 2, fulfillment of these responsibilities associated with transactional impacts would still be accomplished primarily through the curtailment of tagged transactions, and the curtailments would continue to respect current transmission service priorities. As a backstop for those curtailments, a set of recommended generation dispatch changes can be generated for immediate relief if tagging curtailments are ineffective or take too long to accomplish. However, in its investigations, the IDCGTF concluded that the Option 2 relief prescription process, and complex coordination issues, may make Option 2 difficult to implement.

“Option 3 is a progression of the development of Option 2, using the assignment of responsibility for relief, but would differ in the actions taken to achieve necessary relief. Option 3 would depend on the RCs to identify and initiate effective and efficient generation dispatch changes to achieve the required relief instead of curtailment of individual transactions. Option 3 builds on the concepts of Option 2 and can go beyond to address other issues associated with timely congestion management and inadvertent interchange. Option 3 can be adapted in various ways to work with the new market structures. However, the effort to adopt Option 3 will require a coordinated acceptance

by the industry, and will require rigorous technical and business practice scrutiny.

“Option 3 can be implemented at various technical levels. For example, Option 3 could be implemented without the incorporation of real-time data. The real-time data would help refine the ERR/IRR calculation and help RC’s with redispatch choices. However, with improved SDX reporting and merit order incorporation, the ERR/IRR calculations can be refined to an acceptable level, and RC’s have other sources of referencing real-time data to verify unit outputs and flows. In summary, Option 3 may be technically implemented within 1 to 3 years. Policy and legal filing issues may be the critical path in implementing Option 3.”

c. Entergy 3% TLR Threshold Test

ActionConsider Entergy’s request to extend its test of a 3% TLR threshold for three flowgates through June 30, 2005.

Request for extension from EntergyRequest from David McNeill of Entergy:

“Due to unforeseen technical, coordination and confidentiality issues associated with its 3% Curtailment Trial set to end March 31, 2005, Entergy is seeking a one-time three month extension to the original trial. No changes are requested to the originally approved trial procedure or reporting and coordination requirements. Entergy has not yet implemented the requested procedure and is seeking this extension to provide time to compile the data necessary to fully evaluate the effectiveness of the trial. Entergy proposes that the revised trial end date be June 30th, 2005.”

Background

Operating Reliability Subcommittee recommendationThe Operating Reliability Subcommittee, at its September 2004 meeting, agreed to Entergy’s request and passed the following motion:

“Moved that the ORS endorse and recommend to the Operating Committee, for its approval on a trial basis through March 31, 2005, that Entergy be allowed to reduce the non-firm curtailment threshold to 3%, as is currently reflected in Recommendation 6 of the Alliant West TLR Task Force final report, on the Couch-Lewisville 115 kV, Richard-Colonial 138 kV, and Harrison East-Summit 161 kV flowgates.”

From OC’s November 2004 meetingNote: Entergy provided the following narrative.

Recently Entergy transmission has experienced projected post-contingency power flows on its lower voltage transmission system (see map below) that could exceed equipment thermal limits and potentially could exceed Operating Security Limits. Entergy has been unable to relieve those loadings using its own generation nor using the current TLR process. Relief of these high flows is dependent on generation located in other control areas, under another reliability coordinator. Therefore, Entergy is requesting that NERC grant Entergy permission to include a new Step 3C in Entergy’s TLR process to use a 3% Outage Transfer Distribution Factor curtailment threshold to be applied to Transmission Service Priorities 1–5 and NN6 (see table at right), for specific transmission facilities rated at voltages less than 230 kV.

Transmission Service Priorities

Priority 0. Next-hour Market Service – NX*

Priority 1. Service over secondary receipt and delivery points – NS

Priority 2. Hourly Service – NH

Priority 3. Daily Service – ND

Priority 4. Weekly Service – NW

Priority 5. Monthly Service – NM

Priority 6. Network Integration Transmission Service from sources not designated as network resources – NN

Priority 7. Firm Point-to-Point Transmission Service F and Network Integration Transmission Service from Designated Resources – FN

Harrison E-Summit

Hot Springs-Bismarck

Richard-Col. Acad.

Harrison E-Summit

Hot Springs-Bismarck

Richard-Col. Acad.

Entergy found in these situations that parallel path power flows, resulting from point-to-point transmission service granted by other transmission providers, contributes significantly to the facility loading. The impact of these transactions frequently falls in the 3–5% range. Due to the existing curtailment threshold limit of 5%, Entergy has been unable to reduce the impact of those transactions using the TLR process. Consequently, reduction of those loadings could, at times, only be accomplished by redispatching generation in other control areas because redispatching Entergy generation has no effect on the projected overload. In certain circumstances, Entergy finds itself in a reliability situation caused by other transmission providers that Entergy cannot solve by itself either under the auspices of its own OATT or with the existing NERC rules. Analyses of these events has shown that adequate relief could have been achieved had the TLR process allowed the curtailment of non-firm transactions with more than 3% impact on the facility.

This subject has been debated in the abstract at NERC in various working groups, subcommittees, and committees since May of 1999 when NERC decided to de-emphasize the use of Power Transfer Distribution Factor flowgates. We are now into the realm of real, significant risk. Entergy (in addition to MISO and SPP) has a concrete example with no solution under the current rules.

Entergy desires for NERC to lower the curtailment threshold from 5% to 3% for a trial period ending March 31, 2005. If at the end of that period our evaluation indicates that this change has been effective in solving these issues, Entergy will submit a request to implement this change permanently. It should be noted that the total amount of relief required for any given event will not increase as a result of this change. It should also be noted that the expanded pool of lower-priority transmission service schedules available for relief reduces the likelihood that higher-priority service will need to be curtailed.

Item 19. Long-Term ATC/AFC Task ForceThe Operating Committee is picking up this task force from the former Market Committee.

Item 20. MISO Market Startup and Standards Waiver Verification

ActionConsider the following resolution:

“Based on the favorable findings of the NERC Technical Verification Team in its January 27, 2005 report, and previous NERC readiness audits, and recommendation from the Operating Reliability Subcommittee, the Operating Committee is satisfied with MISO’s readiness to implement the NERC policy waivers regarding:

1. The enhanced scheduling agent

2. Energy flow information, and

3. Enhanced congestion management”

MISO will provide an overview of the findings and conclusions resulting from the NERC Technical Verification Team review and analysis of its processes and procedures to ensure compliance with committee-approved waiver requests.

Attachment“NERC Technical Verification Team For MISO Market Waivers,” January 27, 2005.

Background – Chronology of Events

July 2003MISO presented an operating policy waiver request to the Operating Committee at its July 2003 meeting. The minutes of that meeting state:

“David T. Zwergel, who is the Midwest ISO’s manager of area security coordination, reviewed three operating policy waivers, two of which were being requested by MISO on behalf of its control area members and one of which was being requested by MISO and PJM. The waivers that Mr. Zwergel presented were as follows:

1. Enhanced scheduling agent

2. Energy flow information

3. Enhanced congestion management

“The Operating Committee approved the following:

“With NERC and appropriate regional representation, audit and confirm the Midwest ISO’s readiness to perform the functions detailed in the enhanced scheduling agent and energy flow information waivers before they go into effect.

“Furthermore, the OC accepted the waiver requested by MISO and PJM for enhanced congestion management.”

March 2004 – Operating Committee ResolutionAt its March 2004 meeting, the Operating Committee approved the following resolution related to the MISO Reliability Plan:

“Whereas:

1. The NERC MISO/PJM Review Team, on January 15, 2004, recommends approval of the MISO Reliability Plan with certain understandings.

2. The NERC MISO/PJM Review Team believes that Version 4.0 of the Congestion Management White Paper is a viable method of congestion management.

3. The NERC audit team states that MISO has successfully passed the NERC readiness audit with the condition of resolving MISO authority over non-MISO members.

4. MISO has agreed to implement the Readiness recommendations as follows by June 30, 2004:a. Authority issues with non-MISO members and MECS-IMO interface

resolved.b. Information on Load shedding ability of MISO members collected.c. Collection of UFLS and UVLS information complete.d. Voltage and reactive reserve management plan implemented.

And by December 31, 2004:

e. Implementation of formal training program and records in place.f. MISO-wide restoration plan in place.

“With respect to MAPP not taking action on the MISO Reliability plan, the Operating Committee understands that MAPP is not opposed to the Operating Committee’s approval of MISO’s reliability plan at this time, with the understanding that MAPP and MISO are working to resolve the issues between them.

“The Operating Committee respectfully acknowledges the lack of ECAR endorsement of the MISO reliability plan.

“The Operating Committee believes that the MISO/PJM Review Team has addressed ECAR’s issues through the review team’s review and approval of the MISO/PJM Congestion Management Process and the Operating Committee believes these concerns have been adequately addressed.

“Therefore, the Operating Committee approves the MISO Reliability Plan.

“Furthermore, the Operating Committee requests that NERC conduct a review of MISO’s reliability readiness before MISO begins its market operations.”

April 2004 – NERC readiness audit of MISONERC conducted a readiness audit of MISO in April 2004, and found that:

Compliance to PoliciesWith the exception of the authority issues with non-MISO members that must be resolved, the audit team concluded that MISO meets their responsibilities as the reliability coordinator for the safe and reliable operation of the interconnected transmission system for their defined reliability authority area as defined in the policies.

Readiness to Implement Their Reliability PlanWith the authority over non-MISO members as an exception and without making any judgment on MISO ability to implement the LMP market this fall, the audit team found no other impediments to MISO’s ability to implement its RTO reliability plan.

August 31, 2004Subsequently, on August 31, 2004, MISO wrote NERC to confirm that the authority agreements were resolved.

January 24+, 2005 – Technical ReviewDuring the week of January 24, 2005, members of the Interchange Distribution Calculator Working Group, a representative from the Midwest Reliability Organization, a representative of the Interchange Subcommittee, and NERC staff met at MISO’s offices in Carmel, Indiana. The purpose of the meeting was two-fold:

1. The IDCWG tested the IDC processes for receiving MISO market flow information and the handling of that information within the IDC.

2. A sub-team reviewed MISO’s tools, processes, and procedures for implementing the policy (standard) waivers.

MISO staff member Dave Zwergel and IDCWG Chairman Julie Pierce provided an overview of the verification process and the results observed.

February 9–10, 2005 – Operating Reliability Subcommittee actionMISO presented this information to the Operating Reliability Subcommittee at its February 9–10, 2005 meeting, which resulted in the following subcommittee action:

“That the subcommittee accepts the results of the technical verification of MISO readiness to implement the NERC policy waivers and continue with market startup.”

Item 21. Reliability Plans

ActionReconfirm the steps for approving reliability plans and reliability coordinators.

BackgroundNERC expects to receive a new reliability plan from SaskPower to become a reliability coordinator, and revised plans from NPCC and SERC to add New Brunswick and South Carolina Electric & Gas, respectively, as new reliability coordinators in those regions.

The procedure for approving reliability plans is straightforward:

1. The regional reliability council or other reliability organization (such as an RTO or ISO) submits a change in its reliability plan to the Operating Reliability Subcommittee.

2. If the plan calls for creating a new reliability coordinator or significantly changing the “footprint” of an existing reliability coordinator, then NERC will conduct a readiness audit of the reliability coordinator3.

3. The Operating Reliability Subcommittee considers the merits of the plan and the outcome of the readiness audit and prepares a recommendation to the Operating Committee.

4. The OC considers the recommendation from the Operating Reliability Subcommittee and then either approves or rejects the reliability plan.

Beginning in 1997 and until the expansion of PJM and the formation of MISO, the Operating Reliability Subcommittee and Operating Committee generally accepted the reliability plans that the regions submitted to NERC as long as those plans included all the necessary sections and explanations.

On July 31, 2002, the FERC conditionally approved the compliance filings of the former Alliance Companies stating their elections to join either MISO or PJM. One of the conditions to that approval was that MISO and PJM obtain NERC approval of revised reliability plans that address four areas of concern: (1) parallel flows – ATC/AFC calculation; (2) contract tie capacity and electrical peninsulas; (3) differing definitions and procedures between RTOs; and (4) facilities in close electrical proximity under different RTOs.

The Operating Committee and several of its subgroups played a significant role in addressing the conditions that the Commission outlined. This resulted in a number of special NERC meetings, interim approvals, readiness audits, and final resolutions accepting the MISO and PJM reliability plans and their associated congestion management procedures.

The Commission’s reliance on NERC’s expertise, review, opinions, and approvals of the MISO and PJM reliability plans has arguably established a precedent for approving all future reliability plans and revisions to existing plans. For example, NERC expects to conduct readiness audits of all new reliability coordinators from now on.

3 Minor footprint changes require Operating Reliability Subcommittee approval only, with a report to the Operating Committee.

Item 22. Next Meetings June 8–9, 2005 — Montréal, Québec

September 14–15, 2005 — To be determined

December 7–8, 2005 — St. Petersburg, Florida