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N O R T H A M E R I C A N E L E C T R I C R E L I A B I L I T Y C O U N C I L Prince ton Forre sta l Villa ge , 116-390 Villa ge Boule va rd, Prince ton, Ne w Je rse y 08540-5731

Operating Committee Meeting

July 21, 2004  Following Joint Meeting  6 p.m. July 22, 2004  8 a.m.5 p.m.

Four Seasons Hotel 791 West Georgia Street Vancouver, British Columbia V6C 2T4 Phone: 604-689-9333  Fax: 604-684-4555

Agenda

1. Administration a. Arrangements – Secretary b. Announcement of Quorum – Secretary c. Procedures  Secretary i) Antitrust Guidelines  Chair ii) Parliamentary Procedures  Secretary iii) Waiver of Ten-day Advance Requirement for Motions – Chair d. New Members – Secretary e. Introduction of Members and Guests  Secretary

2. Approval of Agenda  Chair

3. Consent Agenda a. Minutes  March 23–25, 2004 Operating Committee Meeting  Chair

4. Information Items a. System Disturbances b. Continuing Education Program Update – Continuing Education, and “Train-the-Trainer” Workshops c. E-Tag Audits d. Interchange Authority Functionality e. Interchange Coordination f. Data Exchange Working Group Scope g. 2003 NERC Compliance Program h. 2004 NERC Compliance Program

5. National Electric Grid Monitoring System – RFI – Don Benjamin

6. NERC Business Plan and Budget – Don Benjamin

Phone 609-452-8060  Fax 609-452-9550  URL www.nerc.com Operating Committee Meeting Agenda July 21–22, 2004 Vancouver, British Columbia

7. Reports from Other Committees  Bill Lohrman, Glenn Ross

8. Operating Committee Organization a. Retirement of MISO/PJM Reliability Plan Review Team and Task Reassignment – Chair b. Functional Model Working Group – Chair

9. Reliability Standards a. Reliability Standards, Version 0 – Gerry Cauley b. Operating Limit Definition Task Force Report – Al Miller

August 14, 2003 Blackout

10. Corrective Actions – Don Benjamin

11. Control Area Self-Assessments  Regional Council Representatives

12. Operations – Real-Time – Larry Kezele a. Implementation of Revised Operating Policies b. Operator “Tools” c. Communications – Hotline d. Definitions of Operating Conditions e. TLR Use

13. Operations Planning – Larry Kezele a. Operations Planning – General b. Communications – Line Outage Information

14. Operator Training and Certification – Don Benjamin

15. System Restoration – Larry Kezele

16. FERC Request for Operating Information – Don Benjamin

17. Reliability Plans a. Control Area “Mapping”  Larry Kezele b. PJM Reliability Plan – Tom Bowe c. Northeast Power Coordinating Council Reliability Plan

18. Reliability Coordinator Plans Task Force  Sam Jones

19. IDC Granularity Task Force – Bob Cummings

20. Flowgate Administration Reference Document – Larry Kezele

21. Long-Term ATC/AFC Task Force – Steve Dayney

22. Frequency Data Warehouse – Brian Nolan

- 2 - Operating Committee Meeting Agenda July 21–22, 2004 Vancouver, British Columbia

23. NERCnet Redundancy

24. Standard 300, “Balance Resources and Demand” – Doug Hils

25. Standard 200, “Operate Within Interconnection Reliability Operating Limits – Ed Riley

26. Standard 400, “Coordinate Interchange – Alan Johnson

27. NAESB Business Practice, “Coordinate Interchange” – Roman Carter

28. NAESB Business Practice, “Inadvertent Payback” – Lou Oberski or Tom Vandervort

29. NAESB Business Practices Subcommittee – Don Benjamin

- 3 - - 4 - Item 1. Administration a. Arrangements Don Benjamin will review the meeting arrangements. The meeting begins on Wednesday, July 21 after the joint OC-PC-MC meeting, and will adjourn on Thursday, July 22 at 5 p.m. A luncheon will be served at noon on both days. (See Figure 1 at right.) b. Announcement of Quorum Mr. Benjamin will announce whether a quorum (two-thirds of the voting members) is in place. NOTE: the committee cannot conduct business without a Figure 1 - Lunch quorum. Please be prepared to stay for the entire meeting. c. Procedures The 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. From Organization and Procedure Manual, “Notice of Committee Agenda:” Attachments “In general, action may not be brought to  Antitrust Guidelines a vote of the committee unless it has been noticed in a published agenda or other  Parliamentary Procedures form of distribution to the committee at least ten (10) business days before the  Organization and Procedures Manual for the NERC Standing meeting date upon which action is to be Committees voted. This requirement for a 10-day notice may be waived either by the approval of the chair or by a two-thirds Action – Waiver of “Ten-Day” rule affirmative vote of the committee’s voting “Ten-day” rule. The chair will waive the rule requiring a ten-day members present at a committee meeting at which a quorum has been established.” 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 Members

Action The Operating Committee will need to formally approve the recommendation from the Nominating Task Force to fill an expected TDU representative vacancy.

Additional Information Regarding Membership On June 15, 2004, the Board of Trustees approved a new slate of Operating Committee members for June 30July 1, 2006

Attachment Operating Committee Membership Table

- 5 - e. Introduction of Members and Guests The chairman will ask the committee members and guests to introduce themselves

Attachment Operating Committee roster

- 6 - Item 2. Approval of Agenda

Action Approve meeting agenda.

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

- 7 - Item 3. Consent Agenda The 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  March 2325, 2004 Operating Committee Meeting

Action Approve minutes.

Attachment Minutes – March 2325, 2004 Operating Committee meeting

- 8 - Item 4. Information Items a. System Disturbances

Attachment 2004 System Disturbances – Quarterly Report

1997 System Disturbances Report

The 1997 DAWG report has been completed and was posted on April 26, 2004. This completed the reports that had not been completed between 1996 and 2001.

2002 System Disturbances Report

The 2002 DAWG report has been drafted. The draft report was given to DAWG on April 7, 2004 for their review. When the DAWG review is completed, the NERC staff will do a final review. The report will be given to the Operating Committee for its approval by August 1, 2004.

2003 System Disturbances Report

DAWG has assembled most of the data for the 2003 DAWG report. Work on this report has been held up due to the August 14, 2003 Blackout investigation and work completing the 1997 and 2002 DAWG report. The DAWG will continue work on the 2003 report after finalizing the 2002 report.

2004 System Disturbances – Update

There have been 30 disturbances in the first six months of 2004. (See attached summary) The only significant event occurred on June 16, 2004, which was the Palo Verde incident. The WECC has requested a detailed disturbance report for this incident. NERC staff and a DAWG member are part of the investigation team.

- 9 - b. Continuing Education Program Update – Continuing Single Learning Activity Education, and “Train-the-Trainer” Workshops providers

American Power Dispatchers’ Attachments Association Entergy Transmission Company  Summary of Changes to the Continuing Education Program Criteria Pacific Northwest Security Coordinator Progress Energy Carolinas,  CE Provider Report: CE Hours Awarded by Provider Incorporated SERC  Announcement, “Train the Trainer Workshop, September 15-16, Southern Company 2004” Western Area Power Administration, Desert-Southwest Area NERC-approved CE Providers – Background utilities and Regional Councils Since the start of the NERC Continuing Education (CE) Program on January AEP Generation Dispatch 14, 2004, the Personnel Subcommittee has identified several changes that are AEP Transmission Operations Ameren required to the administrative manual (http://www.nerc.com/~oc/ce/). These Bonneville Power Administration changes address issues that had not been identified when the Subcommittee British Columbia Transmission brought the manual to the board for approval last October. These changes are Corporation California ISO listed in the table on the following page. CenterPoint Energy Dairyland Power Cooperative ERCOT ISO The NERC CE Program was approved in October 2003. NERC began FirstEnergy Corporation processing learning activity applications on January 14, 2004, and set March 1 HydroQuebec TransEnergie as the first date that actual CE learning activities could commence. Since then, Idaho Power Company ISO New England NERC has received applications from more than 44 entities to become either a Manitoba Hydro Electric Board CE provider for single learning activities, or a NERC-approved CE provider. Midwest ISO The list of approved providers includes utilities, reliability councils, reliability New York ISO NorthWestern Energy, Montana coordinators, ISOs, training vendors and consultants, and a state college. (See Oncor list at right.) Otter Tail Power Company Pacific Gas & Electric Company PJM Interconnection, LLC The attached “CE Provider Report: CE Hours Awarded by Provider” lists the Public Service Company of New number of CE hours that have been awarded since March 1, 2004. Note: The Mexico Puget Sound Energy total number of attendees is inflated because the reports are from all CE SPP providers. Therefore, some individuals are being counted as an attendee Western Area Power Administration, several times. This will remain this way until we can have CE providers enter Electric Power Training Center WECC their rosters on line with reference to NERC certificate numbers. When this Xcel Energy occurs, each attendee would be unique. NERC-approved CE Providers – “Train-the-Trainer” Workshop. The Personnel Subcommittee is hosting a Vendors, consultants, and colleges Train the Trainer Workshop” on September 15–16, 2004 in St. Louis. This Applied Professional Training, Inc. Bismarck State College workshop will help system personnel trainers understand how to write and Decision System International, Inc. measure effective learning objectives when designing training programs L&K International Training intended for system operators. OES-NA, Ltd. Operations-Training-Solutions Powersmiths International, Inc. c. E-Tag Audits and Dynamic Transfer Catalog Shaw Power Technologies, Inc.

Background At its July 2003 meeting, the Operating Committee asked the NERC compliance staff to field-test the new E-Tag audit procedure. When the Resources Subcommittee called Area Interchange Error (AIE) surveys for the seven hours leading up to the August 14, 2003 blackout, the NERC compliance staff called for E-Tag audits in conjunction with those surveys.

- 10 - The AIE/E-Tag audit was designed to compare the net scheduled interchange reported on the AIE survey to net schedules entered into the Interchange Distribution Calculator (IDC). The goal was to audit the IDC without asking the control areas for additional data.

Although the audits did not compare exact sets of data, it was expected that the differences between the two sets of data would be minimal. The August 14, 2003 audit results actually revealed significant differences —over 1,000 MW for several control areas. Follow-up audits were called asking the control areas to reconcile the differences between the two sets of data, and to categorize any untagged schedules. The follow-up audits demonstrated that some dynamic schedules were not tagged or re-tagged properly. The Interchange Subcommittee is following up with several control areas to determine if there were any policy violations.

The Resources Subcommittee called AIE surveys for two hours on January 8, 2004 and for three hours on January 12, 2004. The NERC Compliance staff initiated E-Tag audits on these survey hours. The E-Tag audits for these hours showed significant improvement as compared to the August 14, 2003 audits. Most of the differences noticed in the January audits could be explained based on control area responses received during the blackout audits.

The AIE/E-Tag audits revealed a need to catalog the current control area configurations for dynamic transfers. The Interchange Subcommittee plans to survey the industry and create the catalog. The request to the control areas is expected to go out in August 2004. The NERC compliance staff, in conjunction with the Resources Subcommittee, would like to conduct more frequent (monthly) AIE/E-Tag audits upon completion of the catalog.

The NERC staff is planning to develop an internal tool to increase the efficiency of the audit process. We’ll have a status at the November 2004 Operating Committee meeting.

Doug Hils, chairman of the Interchange Subcommittee, will be available to discuss the catalog, the Dynamic Transfer White Paper, and other subcommittee efforts to address dynamic scheduling of interchange.

Attachment The Dynamic Transfer Catalog letter to the industry will be attached separately. d. Interchange Authority Functionality

Attachment Letter, “Interchange Authority Functionality,” to the Operating Committee, July 8, 2004

Background The Interchange Subcommittee asked the Version 0 standard drafting team to not include the Interchange Authority Function into Version 0 of the NERC standards. The Interchange Subcommittee explained that the IA function’s task should be assigned to other responsible entities. The Interchange Subcommittee formed the Interchange Authority Function Task Force (IAFTF) to operationally define how to apply the IA function into Version 1 of the NERC standards. The task force sent a letter to the Operating Committee that includes the issues and current thinking of the group.

The task force intends to provide recommendations on the Interchange Authority Function at the Operating Committee’s November 2004 meeting. Doug Hils, chairman of the Interchange Subcommittee, will be available to address items related to the work of the IAFTF.

- 11 - e. Interchange Coordination

Attachment Letter, “Interchange Coordination,” to the Operating Committee, July 8, 2004

Background At its June 15, 2004 meeting, the Reliability Coordinator Working Group (RCWG) discussed general problems with interchange coordination between control areas. Examples include the impacts of passively approved transactions, E-Tag timing idiosyncrasies, different methods of confirming interchange schedules, and lack of curtailment acknowledgement.

To address these concerns, the Interchange Subcommittee plans to take a number of actions. Doug Hils, chairman of the Interchange Subcommittee, will be available to discuss the proposed actions with the Operating Committee. f. Data Exchange Working Group Scope

Attachment Data Exchange Working Group Scope

Background On June 23, 2004, Larry Kezele sent the Operating Committee a revised scope for the Data Exchange Working Group that adds two new activities:

Activity 5: Establish and maintain a process for monitoring the availability and timeliness of data exchange and the quality of the data among ISN nodes and their data sources.

Activity 6: Recommend and maintain policies for redundancy and disaster recovery processes for the ISN nodes.

The DEWG reports to the Operating Reliability Subcommittee and the Operating Committee does not need to approve this scope change.

- 12 - g. 2003 NERC Compliance Program

2003 Program Highlights The 2003 NERC Compliance Enforcement Program (CEP) results have been compiled from each regional program and published in the final NERC program report.

Highlights from the 2003 program include:

 Overall compliance with NERC reliability standards has improved slightly, from 94 percent in 2002 to 95 percent this year. However, a number of instances of non-compliance were reported in 2003, including noncompliance with operator certification requirements. The number of instances of non- compliance with operator certification in 2003 represented a marked reduction when compared to 2002. The 2003 program saw approximately a 45 percent reduction in the total number of instances of non- compliance compared to the 2002 program for the planning and operating measures that were monitored in both years. A summary of compliance performance by Region is presented in the table titled, “NERC 2003 Compliance Enforcement Program.” NERC 2003 Compliance Enforcment Program REGION Measure Level 1 Level 2 Level 3 Level 4 Level 4 Non- % Compliance Type submittals

ECAR Planning 5 0 1 2 0 97 Operating 10 0 0 6 0 98 ERCOT Planning 4 0 0 2 0 97 Operating 0 0 0 2 0 99 FRCC Planning 3 2 1 2 0 97 Operating 1 1 0 29 0 94 MAAC Planning 0 0 0 0 0 100 Operating 1 0 0 0 0 97 MAIN Planning 0 0 0 1 0 99 Operating 3 1 3 0 1 99 MAPP Planning 8 1 1 0 0 96 Operating 0 3 0 3 0 99 NPCC Planning 1 0 0 1 0 97 Operating 0 0 0 1 0 100 SERC Planning 12 0 1 2 0 95 Operating 3 0 0 4 0 99 SPP Planning 22 0 2 5 0 84 Operating 2 4 1 28 0 94 WECC Planning 32 1 8 4 0 90 Operating 16 9 19 85 0 90 NERC Totals Planning 87 4 14 19 0 94 Operating 36 18 23 158 1 96

Total 123 22 37 177 1 95 TOTALS 123 22 37 177 1 95

- 13 -  Recommendations were identified to further develop and improve the NERC Compliance Enforcement Program. For example, all blackout investigation recommendations pertaining to the compliance program will be addressed in future programs. Also, the Regions are encouraged to rigorously validate the quality, accuracy, and completeness of self-certifications; to improve enforcement and sanctioning processes; to develop a system for tracking the implementation of the blackout recommendations and recommendations resulting from compliance audits; to refine a reporting process to monitor regional compliance performance throughout the year, including peer review of significant violations; and to participate in the development of new standards.  NERC, in fulfilling its oversight role of the regional compliance enforcement programs, audited the 2002 programs of ERCOT, MAIN, and WECC to confirm their implementation was as approved in their annual plan. These audits complete the initial cycle of NERC regional compliance program audits. The audit process will be revaluated in 2004, building on the lessons learned to promote greater effectiveness. In 2004, NERC will audit the 2003 compliance programs of ECAR, MAPP, and SERC.  NERC reorganized the CEP in 2003. A Compliance and Certification Committee (CCC) was established, the Compliance and Certification Managers Committee (CCMC) was restructured, and the Personnel Certification Governance Committee (PCGC) was formed.  In August 2003, NERC adopted the urgent action Cyber Security Standard. The implementation of this standard will reduce the risks to the reliability of the bulk electric system from compromise of critical cyber assets, including computers, software, and the communication networks that support those systems. As a result, all control areas and reliability coordinators were assessed for compliance with this standard. The results are being submitted in a confidential report to the NERC Board of Trustees. h. 2004 NERC Compliance Program The Compliance and Certification Managers Committee (CCMC) has approved the replacement of the 37 compliance templates currently in the 2004 CEP with a set of 38 revised templates adopted by the board. These templates will be supplemented with four existing templates that address relay misoperations and events. The CCMC will be implementing this revised program on June 1, 2004.

The CEP continues to identify instances of noncompliance with the NERC standards in 2004. In accordance with the Disclosure Guidelines approved by the NERC Board of Trustees, the NERC compliance staff provided details of the instances of non-compliance to the Board of Trustees in a confidential manner identifying the non-compliant entities.

This report included 31 instances of non-compliance that were experienced during the first quarter of 2004, including 23 for operator certification requirements, and four operating security limit violations. All instances of non-compliance were judged by the reporting Regions to not have a significant adverse effect on the reliability of the bulk electric system. Table 2 presents the reported compliance performance results for the first quarter of 2004.

A similar report will be developed for the second quarter of 2004 and presented to the NERC Board of Trustees. The Board of Trustees approved the final Disclosure Guidelines at its June 2004 meeting with an effective date of July 1, 2004. These guidelines call for full disclosure of all confirmed violations of NERC standards. As a result, beginning with the third quarter of 2004, the NERC CEP will publicly disclose all confirmed violations.

- 14 - NERC 2004 Compliance Enforcement Program First Quarter Regional Compliance Performance

Region Violation Reliability Impact Significant ECAR Control Performance During one month, a couple of operating No Standard 2 deviations occurred that did not have any local or interconnection reliability impact. The monthly CPS 2 data was 1.2% below 1 Level 1 violation the 90% requirement. ERCOT None N/A N/A FRCC Operator Certification Note that 3 of the reported violations are No for a FRCC member that is not required by the NERC compliance program to 6 Level 4 violations have certified operators, but is submitted as a regional request. The entities with violations in this area are providing education opportunities to attain full compliance. MAAC None N/A N/A MAIN None N/A N/A MAPP None N/A N/A NPCC None N/A N/A SERC Disturbance Control Potential violation under investigation No Standard pending completion of SERC Compliance Committee reviews. Extenuating circumstances are being 1 Level 4 violation investigated Operating Security Potential violation under investigation No Limit pending completion of SERC Compliance Committee reviews. Planning studies indicate the overload would not have 1 Level 1 violation cascaded and no load would have been shed. SPP Operator Certification These violations, at this time, are not No considered significant to the reliability of the bulk electric system. 3 Level 4 violations WECC Control Performance None Reported No Standard 2

2 Level 1 violations Operating Security None of these reported violations are of No Limit an IROL nature.

1 Level 2 violation The Level 2 violation was a 2.2% overload of a thermal limit. One of the Level 3 violations occurred on 2 Level 3 violations a stability-limited path and lasted 20.2 minutes. While an RMS violation, this would not be a NERC violation. The other Level 3 violation was an 8% overload of a thermal limit. - 15 - Region Violation Reliability Impact Significant

Operator Certification As WECC has reported in the past, No operator certification has been included in the WECC RMS program and WECC 2 Level 3 violations has seen a continuing downward trend in the number of violations being reported.

12 Level 4 violations

- 16 - Item 5. National Electric Grid Monitoring System – RFI

Action Approve forming a joint OC-CIPC task force to monitor this initiative, keep NERC informed of its progress, and provide input to the federal government as necessary.

Attachment National Electric Grid Monitoring System: Request for Information

Background Excerpt from attached RFI (highlights added):

“The Government anticipates contracting for services to implement a National Electric Grid Monitoring System (NEGMS) based on two initiatives proposed between the U.S Department of Homeland Security (DHS) and portions of the electric utility industry. The two initiatives consist of a near real-time portion of the system requiring manual entry of data and a real-time portion of the system using automated data entry. This project seeks to finalize the design concepts of these two initiatives, provide a detailed design for both, and to implement at least an initial phase of both these initiatives including the initial installation of the system. A key component to achieving these goals will be the ongoing collaboration among key electric sector organizations, the Government, and the Contractor for this effort. The purpose of the system is to aid the DHS in maintaining a situational awareness of the state of the nation's electrical grid and to share this information with the electricity sector.

“This system will initially operate between the DHS and a limited number of the North American Electric Reliability Council (NERC) Reliability Coordinator (RC) Region sites. The concept for the near real-time portion of the NEGMS is for personnel at each individual participating RC site to manually enter via a computer monitor information into a preformatted spreadsheet. The spreadsheet will use this information to automatically characterize the condition or "status" of the RC Region's grid. This spreadsheet information and the "status" condition for each participating RC region will be communicated to and stored at the DHS.”

The attachment provides the complete text of this request for information.

Both the DHS and DOE have presented similar concepts to the NERC Reliability Coordinator Working Group over the past several months. One of these concepts is the North American Electric Infrastructure Security Monitoring System (NESEC), which was suspended. The NEGMS appears to be the replacement..

- 17 - Item 6. NERC Business Plan and Budget

Action Discuss Draft of 2005 NERC Business Plan

Background At its June 15, 2004, meeting, the board approved a number of proposed revisions to the 2004 NERC Business Plan and a supplemental assessment for 2004 to cover additional work growing out of the blackout. That revised business plan formed the basis for the July 7, 2004, Draft 2005 NERC Business Plan, which was sent to all the NERC committees under separate cover.

The members of each NERC committee and the regional managers are invited to discuss the draft business plan and offer suggested inputs. Following the committee meetings in Vancouver, each committee executive committee and the regional managers will meet individually by conference call with NERC staff to discuss proposed changes to the business plan. Staff will develop a second draft of the business plan, including projected financials for 2005, for consideration by the board’s Finance and Audit Committee (FAC) at their conference call meeting on August 6. A revised draft of the business plan and budgeted financials will be distributed to the committees on August 13, with comments due September 10. The final draft business plan and budget will be distributed to the NERC committees prior to the October board meeting. The board will be asked to approve then final 2005 NERC Business Plan and Budget at its October 15, 2004, meeting.

Attachment Draft 2005 NERC Business Plan was sent July 8, 2004 by Heather Gibbs.

- 18 - Item 7. Reports from Other Committees Bill Lohrman and Glenn Ross will summarize the actions of the Market Committee and Planning Committee, respectively.

Attachment None

- 19 - Item 8. Operating Committee Organization a. Retirement of MISO/PJM Reliability Plan Review Team and Task Reassignment

Action Retire the MISO/PJM Reliability Plan Review team and assign its tasks to the Operating Reliability Subcommittee.

Background Past Operating Committee Chairman Derek Cowbourne chaired a special joint meeting of the Reliability Coordinator Working Group and the Operating Reliability Subcommittee on July 12, 2002. The scope of that meeting was to begin reviewing seams congestion management issues between PJM and MISO and provide recommendations to the Operating Committee for its formal consideration. Mr. Cowbourne noted that as a matter of policy, NERC requires that all Reliability Coordinators submit revised reliability plans to the Operating Reliability Subcommittee for review whenever there are changes in the Reliability Coordinator’s operating procedures or its membership (“footprint”). Because of the complexity of the seams congestion management issues, Mr. Cowbourne formed the review team, which was comprised of members of the RCWG and the ORS, augmented by members of the Planning Committee’s Reliability Assessment Subcommittee and ATC Working Group. Review team members affiliated with MISO or PJM participated in the team discussions, but were not permitted to vote on review team motions. Mark Fidrych chaired the review team.

Since July 2002, the review team and the Operating Committee have held several meetings to specifically consider revisions to the PJM and MISO Reliability Plans and to review their seams congestion management proposals. While MISO and PJM continue to develop or expand their markets, the work of the review team to review seams congestion management issues has, for all practicable purposes, drawn to a close. Therefore, the Operating Committee should consider retiring the MISO/PJM Reliability Plan Review Team and assigning its tasks to the Operating Reliability Subcommittee. The ORS will invite others to participate in reliability plan discussions as needed. b. Functional Model Working Group

Action Approve formation of the Functional Model Working Group to replace the Functional Model Review Task Group.

Attachment Functional Model Working Group Scope

Background The Functional Model Review Task Group recommends creating a permanent Functional Model Working Group to manage the NERC Reliability Functional Model to ensure that it remains up to date. Version 2 of the Functional Model includes a revision procedure that this working group would follow.

The standing committees would continue to review and approve all changes to the Functional Model. However, the working group itself would report to the standing committees’ executive committees to - 20 - facilitate its management. (Past experience suggests that groups reporting to multiple committees is not a good idea.)

Most of the Functional Model Review Task Group members (see following list) have asked to serve on the FMWG.

Functional Model Review Task Group James A. Byrd – Oncor - Functional Model Review Task Group Chairman Donald E. Badley – Northwest Power Pool Gerald W. Burrows – Kansas City Power & Light Company – Organization Certification Task Force Chairman James D. Cyrulewski – International Transmission Company Albert M. DiCaprio – PJM Interconnection, L.L.C. Mark Fidrych – Western Area Power Administration – NERC Operating Committee Chairman R. S. (Scott) Henry – Duke Power Company – Interconnected Operations Services Subcommittee Chairman Andrew J. Rodriquez – PJM Interconnection, L.L.C. Amir Shalaby and Mike Yealland – The IMO Anthony Jankowski – WE Energies Roman Carter – Southern Company Services, Inc. John F. Stough – AEP Service Corporation (Transmission System) Karl Tammar – New York Independent System Operator Peter Harris – ISO New England

Planning Reliability Model Task Force Members Michael C. Raezer – Tucson Electric Power Company – Planning Reliability Model Task Force Chairman Mike Risen – Basin Electric Power Cooperative Kenneth Haase – New York Power Authority Douglas Collins – Alliant Energy Susan Morris – Southeast Electric Reliability Council Stanley Kopman – Northeast Power Coordinating Council Gregory Vincent – Tennessee Valley Authority Ken Kuyper – Corn Belt Power Cooperative

NERC Staff Virginia Sulzberger – NERC Staff - Planning Committee and Planning Reliability Model Task Force Facilitator William Lohrman – NERC Staff - Market Committee Facilitator John R. Twitchell – NERC Staff Donald M. Benjamin – NERC Staff – Functional Model Review Task Group Facilitator

- 21 - Item 9. Reliability Standards a. Reliability Standards, Version 0

Action Discussion

Background Please see http://www.nerc.com/~filez/standards/Version-0.html for the draft standards. NERC staff will provide additional background information separately. b. Operating Limit Definition Task Force Report

Discussion and Action As directed by the Operating Committee, the Reliability Coordinators have been field-testing the Interconnection Reliability Operating Limit reporting format since May 1, 2003. (See excerpt from the March 2003 Operating Committee meeting minutes below.)

The field-test results, which were inconclusive due to limited data, were presented to the Operating Committee at the November meeting. With limited data to work from, the Operating Limit Definition Task Force (OLDTF) made several recommendations to the Operating Committee in an attempt to identify the degree of understanding of the OLDTF report concepts in the operating community.

OLDTF Chairman Al Miller will present any new conclusions drawn from the field-test since the November Operating Committee meeting, and provide an overview of the Task Forces activities, and recommendation for the future task force activities for the Operating Committee to consider.

The overview of the task force activities will include:

1. Results of the field-test 2. Results of an IROL survey conducted by the OLDTF 3. A proposal to include IROL Informational Reporting (for the reporting of “Near Misses”) for Operating Committee consideration.

Attachment NERC Interconnected Reliability Operating Limit – Informational Reporting, dated July 9, 2004

Background The OLDTF presented its report and initial findings and recommendation to the Operating Committee at its March 2003 meeting. The minutes of that meeting reflect the following (emphasis added):

Operating Limit Definition Task Force Task force chairman Wayne VanOsdol presented the recommendations from the Operating Limit Definition Task Force, focusing on the new definitions of “system operating limit (SOL)” and interconnected reliability limit (IRL).” Mr. VanOsdol suggested that the Operating Committee could implement these definitions by this summer on a “field test” basis. He also discussed the merits of revising the current Operating Policies to incorporate these definitions as well as

- 22 - recommending the definitions to the Operate within Limits Standards Drafting Team for NERC’s new reliability standards.

George Bartlett then moved that the Operating Committee direct the Reliability Coordinators to field test the Operating Limit Definition Task Force definitions for the next six months, and ask the task force to incorporate their work into the reliability standards process. Furthermore, Mr. Bartlett moved that the Operating Committee request that Reliability Coordinators use the IRL violation report form for this summer and evaluate its usefulness.

During the discussion that followed, some members of the committee expressed their concern that the term “IRL violation,” which the task force defines as operating outside and IRL, implies a compliance violation. The task force recommends that an IRL violation occur at the moment that the operating state exceeds the limit, and becomes a compliance violation if this operating state exists for more than 30 minutes.

Mr. VanOsdol noted that the task force was holding a conference call on March 24 and invited the Operating Committee to participate. During that conference call, the task force will discuss the implications of the term “violation” and also consider the other comments from the Operating Committee.

Chairman Cowbourne suggested that the definitions be field-tested beginning May 1 to allow the task force to accommodate the editorial changes that are still needed. After further review, the Operating Committee approved Mr. Bartlett’s motion.

- 23 - August 14, 2003 Blackout Items 10 through 15 cover the recommendations from the investigation of the August 14, 2003 blackout for which the Operating Committee has either a primary or secondary responsibility. These are among the most critical items on the OC agenda, and involve a number of interrelated issues, concepts, and recommendations.

We have organized the recommendations into categories to help understand their relationships. These categories are somewhat arbitrary, but are a good starting point:

1. Assistance and Follow-up 2. Blackout Investigation Procedures 3. Canadian Nuclear Power 4. Compliance 5. Corrective Actions 6. Critical Infrastructure Protection 7. Cyber Security 8. IT Systems 9. Modeling Data and Procedures 10. Operations – Real-Time Operations 11. Operations Planning 12. Physical and Cyber Security 13. Real and Reactive Power Reserves 14. Regulatory 15. Restoration 16. Standards 17. System Protection 18. Training and Certification

Attachments  “Operating Committee Tasks Related to Blackout Recommendations.” This is a list of those items for which the OC has the primary responsibility.  “Blackout Recommendations Summary – By Category.” This is a list of all U.S.-Canada Power Outage Task Force and NERC recommendations.

- 24 - Item 10. Corrective Actions

Action NERC Recommendation 1a – FE, The OC needs to consider the following: MISO, and PJM shall each complete the remedial actions designated in 1. Certification and presentations by ECAR, Attachment A for their respective organizations and certify to the FirstEnergy, MISO, and PJM that they have NERC board no later than June 30, completed their remediation plans, and 2004, that these specified actions have been completed. Furthermore, 2. Verification reports from the NERC assist each organization shall present its teams detailed plan for completing these actions to the NERC committees for technical review on March 23–24, and then determine whether the parties have completed the actions called 2004, and to the NERC board for for in the Board of Trustees’ February 10, 2004, recommendations for approval no later than April 2, 2004. sufficiency. Following your meeting, the OC chairman will then report your determinations to the board. Task Force Recommendation 15 – Correct the Direct Causes of the August 14, 2003 Blackout. Attachments  “Operating Committee Action Regarding Remedial Actions of FirstEnergy, MISO, and PJM,” March 23–25, 2004  Remedial Action Responses. Please see http://www.nerc.com/~filez/remedialactionresponses.html.

Background At the March 2004 OC meeting, MISO, PJM, and FirstEnergy presented their respective remediation plans as required by Recommendation 1a in NERC’s “Actions to Prevent and Mitigate the Impacts of Future Cascading Blackouts,” February 10, 2004. (See text box above.):

At its March 23–25, 2004, meeting the Operating Committee approved the mitigation plans that FirstEnergy, MISO, and PJM submitted.

On April 2, the Board of Trustees, on the recommendations of the OC and PC, approved the MISO and PJM mitigation plans. The board did not approve FirstEnergy’s plan because the Planning Committee was still reviewing additional information it had asked FE to provide regarding its mitigation plan.

On May 7, the board approved FirstEnergy’s mitigation plan on the recommendation of the Planning Committee.

At this meeting, the Operating Committee will hear presentations from FirstEnergy, MISO, and PJM and review the certifications that these organizations submitted to NERC on the completion of these actions. The OC will then hear reports from the NERC assist teams who have conducted verification audits at each of these organizations.

This item is related to the Joint U.S.-Canada Task Force Recommendation 15.

- 25 - Item 11. Control Area Self-Assessments

Action The chairman will ask the Regional Council representatives to provide a brief status of their control areas’ self-assessments.

Attachment Responses from the Regional Councils

Background At its special January 1314, 2004 meeting, the Operating Committee asked that all control areas conduct self-assessments that would, at a minimum, raise the control areas’ awareness of their obligations and responsibilities, and focus their attention on the operating issues that arose during the investigation of the August 14 blackout. Additionally, the committee believes that completing these self-assessments would help the control areas prepare for the upcoming audits and assist in the efficiency of that process.

The committee asked each Regional Council to:

19. Administer the self-assessment to its control area members. 20. Request that each control area report in writing to its Regional Council that the control area has completed the self-assessment and the status of any necessary corrective action, as well as any barriers to mitigating any non-compliance. 21. Provide a status report to the Operating Committee by March 10, 2004, and final report by May 30. 22. Provide NERC with recommendations on how the questionnaires can be improved to better serve the new audit programs described in the Strategic Initiatives.

- 26 - Item 12. Operations – Real-Time The Operating Committee needs to discuss the implementation plans for the following five sets of recommendations related to Operations – Real Time:  Implementation of Revised Operating Policies  Operator “Tools”  Communications – Hotline  Definitions of Operating Conditions  TLR Use

a. Implementation of Revised Operating Policies NERC Recommendation 9a - Evaluate and revise the operating policies and procedures, or provide Discussion interpretations, to ensure reliability The Reliability Coordinator Working Group discussed implementation coordinator and control area of revised Operating Policy 9, and each RC’s assessment of its functions, responsibilities, and authorities are completely and timeframe to come into compliance with the revised policy. The unambiguously defined. RCWG will present an overview of its gap analysis.

Status In Progress.

Background At their March 2004 meetings, the standing committees approved balloting of revised Operating Policies 5, 6, and 9. The committees approved the revised operating policies on April 19, 2004, followed by Board of Trustees approval on June 15, 2004.

Following its discussion of the revised operating policies, the Operating Committee requested the Reliability Coordinator Working Group to provide an implementation plan by May 15, 2004 for committee approval. That plan will ensure that implementation will begin as soon as possible and that all Requirements in Policies 5, 6, and 9 will be implemented by December 31, 2004.

The RCWG developed an Operating Policy 5, 6, and 9 assessment spreadsheet, which was distributed by letter dated May 18, 2004 from Chairman Fidrych to Regional Compliance Managers and Reliability Coordinators. The spreadsheet identified each requirement and sub-requirement for the revised operating policies. For each requirement and sub-requirement the control area or Reliability Coordinator was asked to provide the following information:

1. How is this requirement being done today? The control area or Reliability Coordinator should provide an assessment of its current state in meeting the requirement.

2. Is the control area or Reliability Coordinator compliant with the requirement?

3. If the control area or Reliability Coordinator is not compliant with the requirement, provide a brief gap analysis.

4. For each requirement, the control area and Reliability Coordinator was asked to identify the time frame required to close the gap identified in item 3.

- 27 - 5. For each requirement, the control area and Reliability Coordinator is asked to provide a summary of its implementation plan required to close the gap to become compliant.

The Certification and Compliance Managers Subcommittee noted that it was working on a schedule for assessing compliance with the templates associated with the revised policies; therefore they were not expected to respond to the chairman’s letter.

NERC Recommendation 10 – The b. Operator “Tools” Operating Committee shall within one year evaluate the real-time operating tools necessary for Discussion and Approval reliable operation and reliability The Operating Reliability Subcommittee approved a scope document for coordination, including backup the Real-time Tools Best Practices Task Force (RTBPTF). The task force capabilities. The Operating Committee is directed to report both will address NERC Blackout Recommendation 10 and U.S.-Canada minimum acceptable capabilities for Blackout Recommendation 22. The Operating Committee will be asked to critical reliability functions and a approve the RTBPTF scope document. guide of best practices. Task Force Recommendation 22 - Evaluate and Adopt Real-Time Status Tools for Operators and Reliability Coordinators In progress.

Attachment Scope, “Real-time Tools Best Practices Task Force”

Background NERC Requirement 10 of February 10, 2004, direct its 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 task force supports 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.

Implementation 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

- 28 - 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.

This task force will also address operations planning issues that are covered in Item 13a.

NERC Recommendation 9b – c. Communications – Hotline Evaluate and improve the tools and procedures for operator and Action reliability coordinator communications during Discussion emergencies. Task Force Recommendation 26.A – Tighten communications Status protocols and Upgrade In progress. Communications Systems

Attachment “NERC Reliability Hotline Call Procedures”

Implementation 1. Procedures for operator and Reliability Coordinator communications during emergencies. The Reliability Coordinator Working Group addressed Recommendation 9B by developing the attached draft 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.

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.

- 29 - Task Force Recommendation 20 - Definitions of Operating Conditions. Establish clear definitions for d. Definitions of Operating Conditions normal, alert and emergency operational system conditions. NERC Recommendation 9b - Status Evaluate and improve the tools and Considered but not implemented. procedures for operator and reliability coordinator communications during emergencies.

Implementation The Operating Reliability Subcommittee and Reliability Coordinator Working Group considered the need for definitions of “normal, alert, and emergency” conditions at their June 15–17, 2004 meeting. Neither group believes these terms need a common definition because they are too broad. For example, “emergency” may refer to capacity, energy, transmission loading, or some other operating situation. Furthermore, some tariffs already include these or similar terms.

The additional detail provided in Policies 5, 6, and 9 provide the necessary communications coordination details. e. TLR Use Task Force Recommendation 31 - TLR Use. Clarify that the transmission loading relief (TLR) Status process should not be used in situations involving an actual Complete violation of an Operating Security Limit. Streamline the TLR process. Implementation The Reliability Coordinators understand that the TLR Procedure alone cannot mitigate an IROL violation.

The Operating Reliability Subcommittee discussed this at its June 16–17, 2004 meeting and believe the Reliability Coordinators meet the intent of Recommendation 31.

In addition the ORS noted the following:

23. NAESB should be asked to address the “streamline the TLR process” question. Much of the complexity of the TLR Procedure arises from its alignment with the provisions of the pro forma transmission tariff, especially with respect to the various levels of non-firm, point-to-point transmission service.

24. The IDC Granularity Task Force proposed recommendation to pursue Option 3 would also help streamline the TLR process (see agenda 19).

25. Policy 9, “Reliability Coordinator Procedures,” clearly explains that the Reliability Coordinator is expected to pursue other means of relieving transmission congestion until the TLR curtailment procedure can take effect.

- 30 - Item 13. Operations Planning

NERC Recommendation 13a – The a. Operations Planning – General Operating Committee shall evaluate operations planning and operating Status criteria and recommend revisions in a report to the board within one year. In progress. NERC Task Force Recommendation 30.A – Identification of Operationally Critical Implementation Facilities. NERC should work with the control areas and reliability The Operating Reliability Subcommittee has established a Real-time coordinators to clarify the criteria for Tools Best Practices Task Force (RTBPTF) (see item 12b) to identify identifying critical facilities whose the best practices currently employed for building and maintaining real- operational status can affect the time network models and for performing state estimation and real-time reliability of neighboring areas. 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.

“Critical facilities.” Control Areas and Reliability Coordinator determine “critical facilities” based on NERC's definitions of operating limits, including System Operating Limit and Interconnected Reliability Operating Limit. NERC already includes SOL and IROL definitions in its latest revisions to Policies 5, 6, and 9. In other words, the critical facilities are defined in the context of the SOL and IROL determination, not just as a list of facilities. Recommendation 9c – Evaluate and improve the tools and b. Communications – Line Outage Information procedures for the timely exchange of outage information among control Status areas and reliability coordinators. Complete Task Force Recommendation 30B – Information on Unplanned Outages Implementation The 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.

As of 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: - 31 -  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.

The ORS and RCWG are currently discussing the merits of the SDX-RCIS link.

- 32 - Item 14. Operator Training and Certification

Action Approve the implementation plan for a NERC Power System Operator Task Force Recommendation 19 – Training Study. Improve near-term and long-term training and certification requirements for operators, reliability coordinators, (This could be a resolution supporting the concept of the plan, and operator support staff. recognizing that the detailed scope has not yet been developed.)

Status In progress.

Attachment Excerpt from U.S.-Canada Power Outage Task Force final report, Recommendation 19 (see section with red border)

Implementation Plan NERC will perform with study in two related parts:

26. Job task analysis – Using a “proctored” workshop approach, NERC will conduct a multi- level JTA. Will involve system operators and their managers. The Personnel Certification Governance Committee will manage the JTA. Planned for latter half of 2004. 27. Human performance – The Personnel subcommittee will study human performance needs in 2005 based on the job task analysis. Will include in the NERC 2005 budget.

Background Don Benjamin will lead this discussion. A summary follows.

NERC Recommendation 6 required that “All reliability coordinators, control areas, and transmission operators shall provide at least five days per year of training and drills in system emergencies … prior to June 30, 2004…”

The Joint U.S.-Canada Power System Outage Task Force Recommendation 19 specified that NERC conduct a more comprehensive study as follows:

“In its requirements of February 10, 2004, NERC directed that all reliability coordinators, control areas, and transmission operators are to provide at least five days per year of training and drills in system emergencies, using realistic simulations, for each staff person with responsibility for the real-time operation or reliability monitoring of the bulk electric system. This system emergency training is in addition to other training requirements. Five days of system emergency training and drills are to be completed by June 30, 2004. The Task Force supports these near-term requirements strongly. For the long term, the Task Force recommends that: A. NERC should require training for the planning staff at control areas and reliability coordinators concerning power system characteristics and load, VAr, and voltage limits, to enable them to develop rules for operating staff to follow. - 33 - B. NERC should require control areas and reliability coordinators to train grid operators, IT support personnel, and their supervisors to recognize and respond to abnormal automation system activity. C. NERC should commission an advisory report by an independent panel to address a wide range of issues concerning reliability training programs and certification requirements.”

On April 26, Don Benjamin met with the FERC staff that proposed that FERC and NERC jointly work on the advisory report ( part C above), with each organization paying for one-half of the study expense.

The NERC and FERC staffs then worked together to form the joint panel with representatives from the Institute of Nuclear Plant Operators, U.S. Navy, Iowa State University, Federal Aviation Administration, PJM, and the NERC and FERC staffs. The NERC staff kept the Personnel Subcommittee and Personnel Certification Governance Committee involved in the study scope; both groups believe this study has considerable merit.

On June 15, the NERC Board of Trustees approved NERC’s participation in this study.

However, soon after the board meeting, the joint arrangement did not work out as the NERC and FERC staffs got down to the details on how the study would be performed and the nature of NERC’s involvement.

Over the last few weeks, the NERC staff has been laying out the framework for NERC to perform this study itself under the oversight of the Personnel Certification Governance Committee, who will conduct the job task analysis, and the Personnel Subcommittee, who will conduct the human performance analysis. The NERC staff has had discussions with Captain Matthew Peters of the U.S. Navy (a member of the independent panel) who has provided some excellent thoughts on how to conduct the JTA portion of this study.

Study funding. At this point, we expect to conduct the JTA during the fall of 2004, and expect to fund this part of the study within NERC’s current budget. The Personnel Subcommittee would conduct the human performance analysis in 2005, and we will include the costs for this study in the 2005 budget. (The Personnel Subcommittee will draft a project plan for Operating Committee approval so that these funds can be included in next year’s budget.)

- 34 - Item 15. System Restoration

Discussion and Approval NPCC, MAAC, and, ECAR have developed reports detailing the system NERC Recommendation 11a – The restoration following the August 14, 2003 blackout. A summary of these Operating Committee, working in conjunction with the Planning reports will be presented to the committee. Committee, NPCC, ECAR, and PJM, shall evaluate the black start The Operating Committee will consider charging the ORS with and system restoration performance developing a report that is responsive to NERC Recommendation 11A following the outage of August 14, and U.S./Canada Task Force Recommendation 29. The target date for and within one year report to the NERC board the results of that completion of this effort is February 1, 2005. evaluation with recommendations for improvement.

Recommendation 29 – Evaluate and disseminate lessons Task Force Recommendation learned during system restoration. 29.A – System Restoration Lessons Learned. Evaluate and disseminate lessons learned during system “In the requirements it issued on February 10, 2004, NERC directed its restoration. Require the Planning Planning Committee to work with the Operating Committee, NPCC, Committee’s review to include ECAR, and PJM to evaluate the black start and system restoration consultation with appropriate stakeholder organizations in all performance following the outage of August 14, and to report within one areas that were blacked out on year the results of that evaluation, with recommendations for August 14. improvement. Within six months of the Planning Committee’s report, all regional councils are to have reevaluated their plans and procedures to ensure an effective black start and restoration capability within their region.

“The Task Force supports these requirements strongly. In addition, the Task Force recommends that NERC should require the Planning Committee’s review to include consultation with appropriate stakeholder organizations in all areas that were blacked out on August 14.”

- 35 - Item 16. FERC Request for Operating Information

Action Discussion

Don LeKang from the FERC staff will assist with this discussion. The Operating Committee does not need to take action, but does need to stay apprised of the progress of the Commission’s study.

Attachments  Letter, Alison Silverstein to David Cook, June 18, 2004  Letter, David Cook to Alison Silverstein, June 23, 2004

Background The FERC staff has asked NERC for permission to use certain data to help the Commission conduct operating studies regarding parallel path flows around Lake Eire. Excerpts of the Commission’s request and NERC’s response follow.

From Ms. Silverstein’s letter:

“…the Reliability Division within FERC will be conducting a study to assess the impact of parallel path flows on the interconnected systems around Lake Erie resulting from transactions involving entities in the northeast as point of receipt and point of delivery.

“We will be engaging Open Access Technology Inc. to undertake part of the study, which requires proprietary modeling tools and the associated confidential transaction and network data. NERC’s permission for use of these subject modeling tools and associated data (IDC, SDX, e-Tag, and other data for 2002 through the present) is hereby requested. These data will be used by OATI and not pass into FERC's possession. We expect the completed study and report to contain consolidated information about flows rather than revealing specific individual historic transactions.”

From Mr. Cook’s response:

“NERC grants permission for OATI to use the modeling tools and data solely for purposes of the study described above. NERC also grants permission for the Commission to make use of the results of that study based on NERC’s modeling tools and data. The data is subject to the NERC Confidentiality Agreement for Electric System Security Data, which protects from disclosure information that is less than eight days old. Some of the tags are of long duration and contain information about future transactions. NERC is granting this permission on condition (i) that NERC’s modeling tools and data remain in OATI’s possession at all times and do not pass into FERC’s possession, (ii) that the completed study and report contain only consolidated information about flows from which it is not possible to discern specific individual transactions, and (iii) that OATI select a recent cut-off date and truncate all tags used in its analysis as of that date.

“We strongly encourage you to involve the four affected reliability coordinators (Independent Market Operator in Ontario, Midwest ISO, New York ISO, and PJM) and the three affected regional reliability councils (ECAR, MAAC, and NPCC) at - 36 - the earliest possible opportunity. Their knowledge of the operation of the systems around Lake Erie will be invaluable for the study you have in mind.”

- 37 - Item 17. Reliability Plans a. Control Area “Mapping”

Action Discussion

As part of the reliability plan review, the committee also reviews the current “mapping” of control areas to Reliability Coordinators. Larry Kezele will be available to answer questions.

Attachment “NERC Reliability Coordinator Desks” b. PJM Reliability Plan

Discussion and Approval Tom Bowe, PJM, will provide the committee an overview of PJM’s revised reliability plan, dated June 8, 2004. Following Mr. Bowe’s presentation, the committee will be asked to endorse the PJM Reliability Plan.

Attachments The following documents are included in a zip file posted with the OC agenda for this meeting:

1. Letter – MISO/PJM to NERC OC Chairman – April 5, 2004

2. Congestion Management Process, Version 4.01 – April 2, 2004

3. Readers Guide for the Congestion Management Process – April 2, 2004

4. Letter – MISO/PJM to FERC – April 2, 2004

5. PJM Reliability Plan, dated June 8, 2004 (redline)

6. PJM Reliability Plan, dated June 8, 2004 (clean)

Operating Reliability Subcommittee Action The ORS approved the following motion related to the PJM Reliability Plan and the MISO/PJM Congestion Management Process.

“The ORS endorses the MISO/PJM Congestion Management Process, version 4.01, and the PJM Reliability Plan, dated June 8, 2004.”

Background At the request of the Federal Energy Regulatory Commission, MISO and PJM clarified several issues included in Version 4.0 of their jointly developed Congestion Management procedure. On April 2, 2004, MISO and PJM filed their joint compliance filing with clarifications as ordered by FERC. On April 5,

- 38 - 2004, MISO and PJM notified Operating Committee Chairman Mark Fidrych of the compliance filing and attached Version 4.01 of the Congestion Management Process document, dated April 2, 2004. As MISO and PJM indicated in their letter to Operating Committee Chairman Mark Fidrych regarding Version 4.01:

“The version change signifies that all changes were clarifying in nature and that no substantive changes were made to the processes described within the document.”

The NERC staff understands that all Regional Councils (ECAR, MAIN, and MAAC) have approved this plan. c. Northeast Power Coordinating Council Reliability Plan

Attachment “NPCC Regional Reliability Plan,” dated June 2004

Discussion and Approval A member of NPCC staff will provide the committee an overview of the revised NPCC Regional Reliability Plan, dated June 2004. Following the presentation, the committee will be asked to endorse the NPCC Regional Reliability Plan.

The Operating Reliability Subcommittee will be meeting by conference call on Friday, July 9, 2004 to review the NPCC Regional Reliability Plan. The committee will be provided a summary of any action taken by the ORS related to the NPCC Regional Reliability Plan.

- 39 - Item 18. Reliability Coordinator Plans Task Force

Action Approve scope, including a name change, to Operating Reliability Plans Task Force.

Attachment Proposed Scope for the Operating Reliability Plans Task Force

Background This item was on the March 2004 OC meeting agenda, but there was not sufficient time to address it.

(Excerpt from March 2004 OC meeting agenda)

At its November 21, 2002 meeting, the Operating Committee established a Reliability Coordinator Plan Task Force to develop a new “template” for the reliability plans that the Regions and RTOs have been filing with NERC. The committee took this action to:

1. Incorporate the “lessons learned” from the Reliability Coordinator audits that have been under way for the past two years. This includes:

a. Clarifying acceptable delegation of responsibilities

b. Establishing the appropriate Reliability Coordinator “scope of coverage”

2. Incorporate the tasks of the Functional Model’s Reliability Authority into the Reliability Coordinator’s responsibilities

3. Develop a better criteria for evaluating reliability plans

4. Determine whether revisions are needed to the current Policy 9 or its appendixes

The task force recently concluded that it needs to focus its scope on the implementation of the Reliability Authority in the Functional Model rather than the current roles of the Reliability Coordinator, and is suggesting that the reliability plan should instead specify those organizations that will serve as the Reliability Authority(ies) and Balancing Authority(ies) within the Region.

In November 2003, the Operating Committee agreed to change the purpose of this group as recommended.

- 40 - Item 19. IDC Granularity Task Force

Action The Operating Reliability Subcommittee requests the Operating Committee to approve Option 1 as explained in the “White Paper on the Future of Congestion Management.”

“Option 1 would modify the Interchange Distribution Calculator 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 Interchange Distribution Calculator Granularity Task Force 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.”

Attachments “White Paper on the Future of Congestion Management,” Version 2.1, June 2004

Background For the past few years, the Operating Reliability Subcommittee and Reliability Coordinator Working Group have been discussing the need to improve the accuracy of the Interchange Distribution Calculator calculations. The IDC calculates the effects of every tagged interchange transaction on each transmission facility (or “flowgate”) by using distribution factors. These distribution factors are determined from a power flow analysis that assumes, for the most part, that every control area is a single point on the transmission system. For large control areas, this sometimes results in power flow calculations, and therefore TLR curtailments, that have little effect on the flowgate that needs relief. In some cases, transaction curtailments have actually increased the flow on some flowgates because of the IDC model inaccuracies.

The existing IDC inaccuracies are generally due to lack of precise information given to or used by the IDC regarding which generator or generators should be dispatched in the IDC model to accurately reflect the true impacts of a particular transaction. The lack of precise information is generally referred to as a lack of “granularity.” To remedy this problem over the last few years, the Operating Reliability Subcommittee has agreed, on a case-by-case basis, to create “pseudo” control areas at the request of some marketers to more accurately reflect the effect that some groups of generators have on the flowgates. Doing this increases the granularity of the IDC because it increases the number of points that are used to calculate the distribution factors.

The Operating Reliability Subcommittee formed the IDC Granularity Working Group to investigate and propose technical solutions that can be consistently applied to improve IDC calculation accuracy. The IDCWG has been working for the past few years on IDC granularity concepts and options that range from simply breaking control areas into “zones” as necessary, to more sophisticated, real-time system data calculations, to new ways of calculating the effects of generation dispatch on flowgates, and to new methods of curtailment allocation.

This white paper proposes a method by which ultimate granularity could be implemented in the IDC to evaluate impacts of transactions and appropriate required relief to responsible parties during a TLR event. The paper was presented to the Reliability Coordinator Working Group and the Operating Reliability Subcommittee at their April 2004 meetings. The RCWG passed the following motion related to the white paper: - 41 - “To accept Option 1 for implementation by June 1, 2005, and for the RCWG to ask the Market Committee and IDCWG to develop a functional design specification and business case for a long-term solution for congestion management tools that use the IDCGTF’s Option 3 as a starting point by September 2005 for RCWG review.”

Subsequently, the ORS ratified the RCWG motion and recommended that the North American Energy Standards Board be kept informed of this activity.

Option 1, which the Operating Reliability Subcommittee is recommending be implemented, provides increased granularity in the IDC by incorporating zones that are being used by Transmission Providers in evaluation of transmission service requests. It also improves the accuracy of flows due to network and native load (NNL) calculations by using block loading order data submitted by each Control Area. The changes to tagging and the IDC required to implement this option are relatively minor and may be implemented in part or in whole within one year.

- 42 - Item 20. Flowgate Administration Reference Document

Action The Operating Reliability Subcommittee is requesting Operating Committee approval of revisions to Version 1 of the Flowgate Administration Reference Document, originally approved by the Operating Committee in March 2002. The more significant changes reflected in Version 2 of the reference document are:

1. Changing Reliability Authority Working Group to Reliability Coordinator Working Group – this is an editorial change.

2. Elimination of MRD (Market ReDispatch) Flowgate Types – This coincides with the elimination of the NERC MRD program.

3. Creation of Benchmark Flowgate Types – Such flowgates are used internally by the IDC as a quality assurance measure by serving as a means to monitor differences in calculated transfer distribution factors during base case model changes

4. Changing Operating Security Limit (OSL) to Interconnected Reliability Operating Limit (IROL) – This will align the Reference Document with recent Operating Manual changes.

The Distribution Factor Working Group prepared these revisions for the Operating Reliability Subcommittee.

Attachment Flowgate Administration Reference Document, Version 1, dated March 21, 2002

Flowgate Administration Reference Document, Version 2, redline

- 43 - Item 21. Long-Term ATC/AFC Issues

Action Discussion

Follow-up to Steve Dayney’s presentation at the joint session.

- 44 - Item 22. Frequency Data Warehouse

Action The Resources Subcommittee requests that the Operating Committee approve the funding for this project. The Committee approved the project scope in July 2003.

Note: potential vendors will be asked to excuse themselves from the Operating Committee meeting when the committee discusses the costs for this project.

Attachment Standards & Project Implementation Plan, “2003-11 – Frequency Data Collection and Analysis”

Background From July 2003 OC meeting agenda:

“The Resources Subcommittee is recommending that NERC establish a “data warehouse” to store interconnection frequency sample data. When the Operating Committee approved the control performance standards several years ago, it did so with the agreement that Interconnection frequency performance must not deteriorate. Therefore, the Resources Subcommittee needs to collect Interconnection frequency samples and analyze its statistical distribution from year to year.

“The current control performance standards were established under a mandate by the Operating Committee that Interconnection frequency under the CPS1 and CPS2 control criteria should remain the same as the 19931994 base line year. Data on the Interconnection frequencies is therefore vital to ensuring that the performance standards and reliability targets set by NERC are being met. Yet, at the same time, data is becoming more difficult to obtain and manpower to process the information more scarce.

“In the past, NERC has relied on volunteers to supply the frequency data from the three Interconnections and has relied on NERC staff to perform the data processing. Reliance on voluntary data gathering is becoming increasingly unfeasible for many reasons: cutbacks in staffing by most utilities, shifting of personnel among positions and loss of continuity, incompatible data from multiple sources, and reliance on single sources with resulting potential for bad data. Likewise, processing of the data has also become problematic due to constantly changing data sources requiring programming changes, and increasing need for consistency and sophistication of required data reporting.

“To establish a more permanent and systematic approach for analyzing the frequency performance of the Interconnections, the Resources Subcommittee Frequency Task Force has prepared a Standards and Project Implementation Plan (SPIP) detailing the necessary requirements for frequency collection and processing. The SPIP entitled, “Frequency Collection and Data Warehousing,” addresses the issues of what data is to be collected, how the data is to be archived, and what periodic, statistical reports are required .”

From November 2003 OC agenda:

“In July 2003 the Operating Committee approved developing a frequency data warehouse that would help NERC investigate frequency disturbances, calculate Interconnection frequency response surveys, and prepare reports on Interconnection frequency behavior when requested by the NERC Operating Committee. In addition, the Resources Subcommittee will benefit from the periodic interconnection frequency reports specified within the project. The RS will utilize these reports to determine the proper settings for CPS tuning parameters (i.e.,1 and 10) to ensure proper Interconnection frequency performance. Finally, NERC may need to record Interconnection frequency as part of the inadvertent interchange payback business practice that NAESB is developing. - 45 - “The Operating Committee was expecting a report at this meeting from the Resources Subcommittee and NERC staff on final project costs. However, the August 14 blackout investigation temporarily superceded work on the frequency warehouse project. NERC staff expects to issue a Request for Proposal in early November. We will send a copy to the Operating Committee and return in March 2004 with the final details.”

Activity since November 2003 OC meeting:

At the November Operating Committee meeting, the Resources Subcommittee was asked to refine the details of the frequency data warehouse project and report back to the Operating Committee its findings. Since November, the Frequency Task Force acting on behalf of the Resources Subcommittee has performed the following as a means of refining the project plan details:

1. On November 7, 2003, the Frequency Task Force issued its Request for Proposal. The Request for Proposal was designed to allow vendors to bid on just the data collection hardware, the data processing software, or both.

2. By the close of business on January 9, 2004, the Frequency Task Force had received proposals from 17 different companies offering a total of 21 project options. Three of the vendors bid only the data processing with the remaining 14 vendors bidding both parts.

3. During the remainder of January, the Frequency Task Force evaluated all of the proposed solutions on their technical merits and corporate resources.

4. February, March, and April were spent evaluating the remaining six vendors on all aspects of the project, including cost. Of this group of six, one data processing only vendor remained. Several rounds of clarification (technical, financial, and corporate) questions were issued to the prospective vendors, including the severability of their proposals.

5. On May 6, 2004, a vendor presentation meeting was held to allow for bidirectional questions between the prospective vendors and the Frequency Task Force. At this meeting, both of the remaining vendors presented sample solution systems, including one live data example.

6. After the vendor presentation meeting, the Frequency Task Force reviewed each proposal and presentation to find the areas that matched up for an apples-to-apples comparison and areas that didn’t match up for value and benefits.

- 46 - Item 23. NERCnet Redundancy

Action Rewrote the Action The Operating Committee needs to discuss the merits of adding a redundant section network for NERCnet. Considering that:

1. The NERCnet contract ends in November,

2. The Operating Reliability Subcommittee is still considering the need for adding this redundancy, and

3. The ORS’s next meeting is in September, the Operating Committee needs to discuss the possibility that the Operating Committee Executive Committee may need to approve the NERCnet Redundancy project before the OC’s next regular meeting.

Telecommunications Working Group chairman Bonnie Bushnell and NERC’s project manager Brian Nolan will review this project as well as its costs with the Committee.

Note: potential vendors will be asked to excuse themselves from the Operating Committee meeting when the committee discusses the costs for this project.

Background The Telecommunications Working Group and NERC staff manage the NERCnet Additional system. The TWG reports to the Operating Reliability Subcommittee, which has background been discussing the pros and cons of contracting for a second, or backup, frame relay network. Facts about NERCnet and the Telecommunications Working Group follow.

NERCnet facts:

 NERCnet is a frame relay network – actually a “network of Frame Relay at a Glance networks.”  The Interregional Security Network (ISN) was the first Frame relay is a telecommunication service designed for cost-efficient application that NERC deployed over NERCnet. data transmission for intermittent  Deregulation of the industry brought the need to add more traffic between local area networks applications to the network. (e.g. the Reliability Coordinator (LANs) and between end-points in a Information System, Interchange Distribution Calculator, wide area network (WAN). Frame relay puts data in a variable-size unit etc.) called a frame and leaves any  Even though NERCnet is a frame relay network, it has a necessary error correction single “backbone” – therefore it does not provide total (retransmission of data) up to the redundancy end-points, which speeds up overall data transmission. For most  The backbone network itself is a single point of failure services, the network provides a  NERC’s Contract with the network provider will expire 11- permanent virtual circuit (PVC), 04 which means that the customer sees a continuous, dedicated connection From TWG Scope: without having to pay for a full-time leased line, while the service provider figures out the route each Purpose frame travels to its destination and The Telecommunications Working Group (TWG) is can charge based on usage. responsible for supporting the telecommunications needs of From searchNetworking.com the Reliability Coordinators and other entities identified by Definitions, All Rights Reserved, Copyright 2000 - 2004, TechTarget - 47 - the Operating Reliability Subcommittee and for developing standards and practices used to plan, implement, operate, and maintain telecommunications facilities for NERCnet and other communications applications. Activities include:

1. Recommending standards and practices to the Operating Reliability Subcommittee on the development, implementation, and operation of the telecommunications facilities for NERCnet and other communication applications as assigned.

2. Responding to requests for network telecommunications services by recommending appropriate technologies to committees, subcommittees, and NERC staff.

3. Identifying and recommending to the Operating Reliability Subcommittee any modifications to network architecture, bandwidth allocations, security, management requirements, management tools, methods, and performance indicators.

4. Assisting in the preparation of specifications for requests for proposals, recommend potential vendors, assist in bid evaluations, and make recommendations for award of contracts to the Operating Reliability Subcommittee.

5. Establishing security guidelines and minimum requirements for the protection of NERCnet.

- 48 - Item 24. Standard 300, “Balance Resources and Demand”

Action Discussion

Drafting Team member Doug Hils will lead this discussion.

Status The drafting team is reviewing comments from the latest posting period that ended July 2.

Attachment Please see http://www.nerc.com/~filez/standards/Balance-Resources-Demand.html for latest draft.

Background The Balance Resources and Demand Standard scope is to maintain interconnection frequency within a predefined profile under all conditions (i.e. normal and abnormal) to prevent:  Frequency-related instability,  Unplanned tripping of load or generation, and  Uncontrolled separation or cascading outages that adversely impact the reliability of the interconnection.

Version 2, of the Balance Resources and Demand Standard was posted for public comment through July 2, 2004. The Standard Drafting Team is reviewing and responding to the comments.

Major enhancements that were incorporated into the standard from version 1:

1. Retained CPM-1 but dropped CPM-2 (CPM-60)

2. Dropped AOM and DEM as measures but retained concepts through revised BAAL

3. Changed BAAL calculation to be frequency-dependent (eliminated fixed diversity factor)

4. Moved development of Limits from procedures to standard

5. Aligned language to conform to the IROL Standard

6. Eliminated lots of specialized terminology

7. Used frequency-related relay settings to establish interconnection-wide limits

Key features of the BRD Standard’s Balancing Authority ACE Limits (BAALs) are:

 Each BA’s BAALs are based on the real-time interconnection frequency error as well as the BA’s Frequency Bias

 BAAL represents the maximum amount of frequency error allocated to each BA at any moment in time

- 49 -  BAALs include a Tv , the maximum time that a BAAL can be exceeded without exposing the interconnection to unacceptable risk such as a second contingency. BAAL Tv shall be limited to 30 minutes.

 If all BAs operate within their BAALs, no Frequency Trigger Limits will be exceeded

 BAALs are set so that each BA can exceed its BAAL without penalty as long as the

duration isn’t greater than Tv

 BA’s must report all instances of exceeding Frequency Trigger Limits for time greater than

Tv or of exceeding Frequency Abnormal Limit for any length of time

- 50 - Item 25. Standard 200, “Operate Within Interconnection Reliability Operating Limits”

Action Discussion

Drafting team chairman Ed Riley will lead this discussion.

Status The drafting team identified a potential conflict with the Determine Facility Ratings Standard 600—and is exploring options available to move the standard forward. Either the definition of an IROL must be revised, or the requirements for establishing System Operating Limits (contained in Requirement 603 of the Determine Facility Ratings Standard) must be modified.

Also, the Balance Resources and Demand Drafting Team noted a potential conflict with Standard 300, also related to Interconnected Reliability Operating Limits, and Mr. Riley will explain the issues.

Attachments Please see http://www.nerc.com/~filez/standards/IROL.html for latest draft.

During the posting window of Standard 300, Balance Resources and Demand, an issue was brought forth relative to the coordination of Balancing Authorities ACE Limits (BAALs) with Standard 200, Interconnection Reliability Operating Limits (IROLs). The concern addresses possible gaps between standards IROLs/SOLs/BAALs/etc., with the goal of protection of the Interconnection transmission system.

The following example was presented to the BRD SDT: Should a BA drag on the Interconnection and the frequency is close to 60 Hz an IROL or SOL may result. In order to clear the violation a TLR will probably be called. Those BAs properly using the transmission grid and paying for its use will be impacted by the TLR. The BA who is dragging does not appear as a schedule and therefore will not be cut, yet may be a large part of the problem. If the BA is dragging sufficiently (which it could under the new standard if the frequency is close to schedule), a TLR may or may not be sufficient to relieve an SOL or IROL.

Possible solutions to this to concern:

 The BRD drafting team acknowledges the problem and propose tighter coupling of a BA ACE to its impact on the transmission system possibly through a linked SAR.

 NERC Standards Process may develop a methodology for all standards (i.e. the BRD, IROL, Coordinate Operations, and other standards) to comprehensively and interactively protect the interconnection from both frequency and transmission-related reliability risks.

 Evaluate and expand Standard 200, “Operate Within Interconnection Reliability Operating Limits,” standard requirements to include, as a minimum, parameters on real-time frequency error.

 Review and enhance the TLR process and its related standard requirement(s). The TLR process provides an advantage to unscheduled energy over scheduled energy in that it only attempts to manage scheduled energy. If the TLR process managed both scheduled and unscheduled energy equitably, the described problem would not exist. The RA has each BA’s ACE within its footprint and is responsible for implementing the TLR process.

- 51 -  Proceed with the current standards requirements, ensuring the Regions set limits on control error; not an Interconnection control error.

- 52 - Item 26. Standard 400, “Coordinate Interchange”

Action Discussion

Background The Coordinate Interchange Standard Drafting Team has posted the Coordinate Interchange Standard for a round of public comments. The drafting team is currently addressing the public comments and will post responses to the comments soon.

The drafting team’s posting included a reference document that deals with issues concerning Version 1 of “Interchange.” The public comments did not provide a clear direction from the industry on these issues. Alan Johnson will provide an overview of those issues and will be available to address questions from the committee.

- 53 - Item 27. NAESB Business Practice, “Coordinate Interchange”

Attachment See NAESB website for current postings (http://www.naesb.org/weq/weq_cibp.asp).

Background NAESB’s Coordinate Interchange Business Practice (CIBP) Standard, Version 1 was approved by the NAESB Executive Committee and NAESB’s general membership.

NAESB’s Business Practice Subcommittee (BPS) posted Version 0 of the Coordinate Business Practice Standards for comment. Version 0 includes business practices associated with NERC Policy 3. The Version 0 standard differs from the Version 1 standard in that the Interchange Authority Function is excluded in Version 0.

NAESB’s Coordinate Interchange Business Practice Task Force, NERC’s Interchange Subcommittee and Coordinate Interchange Standard Drafting Team, have worked jointly to ensure that the scheduling of interchange is fully covered under the respective standards.

Roman Carter, chairman of the NAESB Coordinate Interchange Business Practice Task Force, will provide a presentation on the NAESB Coordinate Interchange Standards.

- 54 - Item 28. NAESB Business Practice, “Inadvertent Payback”

Action Discussion.

Lou Oberski or Tom Vandervort will make a brief presentation to the Operating Committee on the status of this business practice.

Attachments Please see http://www.naesb.org/weq/weq_iiptf.asp for more details.

Background The NAESB Wholesale Electric Quadrant Inadvertent Interchange Payback Task Force (IIPTF) continues to develop business practices on settling inadvertent interchange. The proposed IIPTF inadvertent interchange business practice includes:

1. Inadvertent Payback business practice will incorporate a frequency bandwidth in which inadvertent energy accumulated within the frequency bandwidth is paid back in kind or financially. Inadvertent energy accumulated outside the frequency bandwidth shall be settled on a financial basis.

2. Inadvertent Interchange accumulation data will be provided by NERC.

a. NERC has agreed to provide inadvertent energy and frequency deviation measurements with hourly granularity. The IIPTF will accept the current limitation of monthly inadvertent measurement reports until such time that technology and NERC implement its hourly granularity measurements.

3. Inadvertent will be measured, verified, and reported in hourly granularity.

4. The specified frequency bandwidth is plus or minus 20 mHz around scheduled frequency.

5. Inadvertent energy settlement inside the frequency bandwidth will be as it is today or financial.

6. Inadvertent energy settlement outside the frequency bandwidth shall be financial.

7. Settlement entity will identify, summarize, and issue statements to BAs to payback or receive energy, cash, or a combination of both.

8. Price Discovery — To Be Determined. The Inadvertent energy price outside the frequency bandwidth will be a fixed price or may be adjusted through a price discovery methodology.

9. Prior to full implementation there will be a one-year test period.

- 55 - Item 29. NAESB Business Practices Subcommittee

Action Discussion

Attachment NAESB Memo, “Action Plan for Developing Version 0 Business Practices Associated with NERC Version 0 Reliability Requirements”

Background The NAESB Business Practices Subcommittee has agreed to develop a number of “shadow” business practices that would be extracted from the NERC Reliability Standards, Version 0. The attached memo explains the Subcommittee’s proposal that it will present to the Joint Interface Committee on July 16.

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