N ORTH A MERICAN ELECTRIC R ELIABILITY C OUNCIL Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731 Operating Committee Meeting July 11 12, 2001 Indianapolis, Indiana Minutes A regular meeting of the NERC Operating Committee was held on July 11 12, 2001 in Indianapolis, Indiana. The meeting notice, agenda, and attendance list are affixed as Exhibits A, B, and C, respectively. Individual statements and minority opinions are affixed as Exhibits D and E. (There were no comments.) The meeting was convened at 9:14 a.m. Committee chairman Derek R. Cowbourne presided. NERC s director of operations, Don Benjamin, reported that a quorum was present, and confirmed the following substitutions: Jerry McElyea for James Fuhrmann Robert Amato for Gary Gillis Selection of Operating Committee Secretary At the chair s recommendation and by unanimous consent, the Operating Committee selected NERC s director of operations Don Benjamin to serve as the Committee secretary during Mr. Cowbourne s term as chairman. Approval of Minutes Upon motion by Mike Calimano, the minutes of the March 28 29, 2001 Operating Committee meeting were approved. Waiver of Ten-day Rule for Motions Chair Cowbourne waived the ten-day agenda notice requirement in Section IV.D of the Standing Committees Organization and Procedures Document. (See text box at right.) Selection of Executive Committee Nominating Task Force chairman Gerry Burrows recommended that John A. Anderson, Ross Phillips, and Walter A. Johnson be elected to serve on the Operating Committee Executive Committee along with the Committee chairman and vice chairman. Mr. Burrows noted that the Nominating Task Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com Waiver of Section IV. D. In general, an action may not be brought to a vote of the committee unless it is noticed on a published agenda at least ten (10) business days prior to the meeting date upon which action is to be voted. This requirement for a 10-day notice may be waived either by the approval of the committee chair or by a two-thirds affirmative vote of the committee s voting members present at a committee meeting at which a quorum has been established.
Operating Committee Meeting Minutes July 11 12, 2001 Force considered geography as well as Operating Committee experience in developing the slate of candidates. The chair then asked for nominations from the floor. Committee member Tim Bush noted that the recommended slate did not include anyone from the generation-supply side of the industry. Hearing no additional nominations, Mr. Burrows then moved to accept the Nominating Task Force s recommended slate, which the Operating Committee approved. Past Chairman Position Chair Cowbourne asked William C. Phillips to serve as the Operating Committee s Past Chairman, and Mr. Phillips accepted. Operating Committee Executive Committee Actions Committee vice chairman Mark Fidrych moved to ratify the Executive Committee s approval of: Revisions to Policy 5, Emergency Operations, Section B Distribution of the draft Approach to Action from the Critical Infrastructure Protection Working Group Several budget items. (Please refer to the meeting agenda for details). The Committee approved the ratification of the Executive Committee actions by unanimous consent. Subcommittee Organization and Procedures Document The secretary briefly reviewed the draft Subcommittee Organization and Procedures document that explains how Subcommittee members and officers are elected and how the Subcommittees conduct their business. He explained that the Procedures were not new, but had never been committed to writing and Operating Committee approval. It was on Scott Moore s motion that the Operating Committee then approved the Subcommittee Organization and Procedures document. Control Area Certification Procedures for Southwest Power Pool and East Central Area Reliability Coordination Agreement NERC s director of compliance David Hilt briefly reviewed the SPP and ECAR draft Control Area Certification Procedures. Gerry Burrows moved to approve the SPP Procedures. In the discussion that followed, Mr. Hilt explained that the SPP Procedures were in line with the NERC Control Area Certification Procedure. The Committee then approved the SPP Control Area Certification Procedure. Pat O Loughlin moved to approve the ECAR Control Area Certification Procedure. Mr. Hilt explained that the ECAR Procedure did not include a NERC representative on the Control Area Review Team. Dick Ingersoll then moved to amend Mr. O Loughlin s motion by adding the requirement that ECAR include a NERC representative on the Control Area Review Team. After discussion, Mr. Ingersoll s amendment was approved, as was Mr. O Loughlin s motion as amended. Midwest ISO Security Plan David Zwergel, Manager of Area Security Coordination from the Midwest ISO, presented the Midwest ISO - 2 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 Regional Transmission Organization Security Plan for Operating Committee approval. A copy of his presentation is affixed as Exhibit F. During and following Mr. Zwergel s presentation, the Operating Committee members asked a number of questions including: How MISO will share data and coordinate operations with other RTOs How MISO will coordinate operations among its different areas (through separate operating desks in Indianapolis and St. Paul both of which will use the same operating services and procedures) Effective date of MISO operations (December 15, 2001) The Operating Committee then discussed the general issue of how to coordinate Regional security plans with the RTO security plans that cover those Regions. (In this case, MISO is within MAPP, MAIN, and ECAR.) The Committee also discussed possible seams issues and the need to keep RTO and Regional security plans updated as RTO membership changes. Jerry Hagge then moved to approve the Midwest ISO Regional Transmission Organization Security Plan with the provision that the Regional Councils that include the MISO revise their security plans accordingly. Vice chairman Fidrych, who is also the Security Subcommittee chairman, noted that the Security Subcommittee will review all RTO as well as Regional security plans to ensure they are coordinated. Following further discussion, the Operating Committee approved the Midwest ISO Security Plan. Reliability Assessment Subcommittee Report on Summer Operations Reliability Assessment Subcommittee chairman Ed Weber reviewed the Subcommittee s assessments of summer 2001 operations. A copy of his presentation is affixed as Exhibit G. The Committee asked Mr. Weber if the Subcommittee is able to measure transmission adequacy. Mr. Weber explained that the Reliability Assessment Subcommittee has not developed an effective way to measure transmission adequacy, and can only assess generation adequacy at this point. California ISO, Pacific Northwest, New York City Following Mr. Weber s overview, the Operating Committee then heard reports from Ed Riley (California ISO), Paul Arnold (Northwest Power Pool), and Mike Calimano (New York City). Messrs. Riley s and Arnold s presentations are affixed as Exhibits H and I, respectively. Las Vegas Mark Fidrych reported on the July 2, 2001 load-shedding event in Las Vegas (Nevada Power.) He explained that high temperatures, unit outages, and lack of available generation imports forced Nevada Power to interrupt approximately 100 MW of firm load to bring their Area Control Error to within acceptable limits. ERCOT ISO Jim Byrd explained that the ERCOT ISO was scheduled to implement customer choice by January 2002 and was expecting to begin operating as a single Control Area on July 20, 2001. He noted - 3 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 that the ISO was performing exhaustive tests to make sure that it could operate reliably as a single Control Area. Transfer Capability Working Group After concluding its discussion of summer 2001 operations, NERC s project director Robert W. Cummings noted that the Planning Committee has postponed approving the scope of the Transfer Capability Working Group to provide an opportunity for input from the Operating Committee s Transmission Subcommittee and Security Subcommittee. (Secretary s note: The PC, TS, and SSC officers conferred on July 23, 2001). NERC Projects Mr. Cummings reviewed the status of a number of ongoing and pending projects including their estimated completion, time, and cost. The Operating Committee discussed how it approves projects and their corresponding costs, and raised the following points: The need for the sponsoring Subcommittee or Working Group to provide a priority for the project as well as cost-benefit analysis. The Committee s responsibility for ranking and approving budget items including the use of its Executive Committee to approve projects between Operating Committee meetings. The need for more in-depth project descriptions, purpose, and operations costs. The need to keep budget estimates confidential during negotiation discussions with vendors. Mr. Cummings briefly reviewed the specifications for a central repository that would serve as the data storehouse for electronic scheduling. He noted that he would approach the Operating Committee in November to approve this project. A copy of Mr. Cummings presentation is affixed as Exhibit J. E-Tag Specification Version 1.7 Interchange Subcommittee chairman Charles Yeung joined Bob Cummings to present a summary of the features in the E-Tag Version 1.7 Specification. A copy of their presentation is affixed as Exhibit K. Mr. Yeung explained that E-Tag Version 1.7 is scheduled for implementation on October 25, 2001. This led the Operating Committee to a lengthy discussion about the transition from E-Tag Version 1.67 to the new version 1.7. Scott Moore noted that the Control Areas of some RTOs were left with a dilemma because they would need to expend considerable effort converting to E-Tag Version 1.7 by October 25, but would use the new version for less than two months because the Regional Transmission Organization would take over the scheduling process on December 15, 2001. Transaction Information System Working Group chairman Andy Rodriquez noted that RTOs argue the opposite point that they would have to implement E-Tag 1.67 now only to abandon it on December 15 when they assume full scheduling responsibilities. The Operating Committee spent considerable time discussing these points. Jerry Hagge then moved to approve E-Tag Version 1.7 and the attendant changes that would be needed to the Interchange Distribution Calculator. In the discussion that followed, Mr. Cummings explained that most of the NERC expense incurred for version 1.7 approximately $500,000 would be required for changes to the IDC, not to the E-tag system itself, which is provided by various vendors or by the users themselves, not by NERC. - 4 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 Noting that the Interchange Subcommittee and Transaction Information System Working Group need to continue working on the new E-Tag Specification, Mark Fidrych then moved to amend Mr. Hagge s motion by adding the following, The technical details [of the Specification] may need to be modified to address errors and ambiguities as the Specification continues to be refined during programming, testing, and training. After discussion, the Operating Committee approved Mr. Fidrych s motion and then approved Mr. Hagge s motion as amended. The Operating Committee addressed the Interchange Subcommittee s recommendation that Generation-Providing Entities and Load-Serving Entities be allowed to approve tag requests. Howard Gugel then moved That Generation-Providing Entities and Load-Serving Entities be granted the right, but not the obligation, to approve tag requests to use their generation or load. If a GPE or LSE do not specify (register) an approval service, then approval on behalf of a GPE and LSE is performed by the host Control Area. After further discussion, the Operating Committee approved Mr. Gugel s motion. Mr. Yeung discussed the relationship between NERC Operating Policies and Operating Systems or tools. He explained that the Operating Committee generally believes that Operating Policies should provide the basis for developing system tools. On the other hand, Operating Policy revisions entail a lengthy process, which can hamper the implementation of new technology for system tools. The Operating Committee then returned to its discussion of the transition from E-Tag Version 1.67 to Version 1.7. Mark Fidrych moved to direct the NERC staff to work with the OASIS Standards Collaborative, Transaction Information System Working Group, Interchange Distribution Calculator Working Group, Market Interface Committee, Control Areas, Transmission Providers, and Regional Transmission Organizations to develop a transition plan from the current E-Tag Version 1.67 to Version 1.7. The transition plan would help mitigate the incompatibilities between the two E-Tag versions associated with the E-Tag 1.7 target implementation date of October 25, 2001, and the various RTO implementation dates. The Operating Committee then discussed the advantages and disadvantages of allowing staggered implementation dates for E-Tag Version 1.7. Mr. Cummings explained that versions 1.67 and 1.7 were incompatible and that the changeover needs to occur simultaneously for E-Tag providers as well as the IDC service. After further discussion, the Operating Committee approved Mr. Fidrych s motion. Market Interface Committee Action Items Market Interface Committee secretary Gerry Cauley reviewed the Market Interface Committee s actions from its July 10 11, 2001 meeting. A copy of Mr. Cauley s summary is affixed as Exhibit L. Issues for NERC Mr. Cauley then organized a brainstorming session during which the Operating Committee members were asked to develop a list of important issues that NERC needs to address. These could be both technical issues from an Operating Committee perspective as well as general issues for the NERC Board of Trustees. The Committee members formed six groups with each group listing its issues on separate flipchart pads. At the end of the brainstorming session, secretary Don Benjamin collected the flipchart notes for consolidating into a single list that evening and distribution to the Committee the next day to provide the Operating Committee members an opportunity to rank the issues. The issues list is affixed as Exhibit M. - 5 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 Adjourn for the Day The Operating Committee meeting was adjourned for the day at 5:30 p.m. Reconvene The Operating Committee meeting was reconvened on July 12, 2001 at 8 a.m. Committee chairman Derek R. Cowbourne continued to preside Standards Task Force NERC s compliance director David Hilt reviewed the latest activities and recommendations of the Standards Task Force. A copy of Mr. Hilt s presentation is affixed as Exhibit N. (The Task Force s Recommendations are shown in the text box on the right.) Mr. Hilt discussed the latest version of the Recommendations Organization Standards Manual, which was included in the Operating Committee s agenda background committee structure material. The Operating Committee spent considerable time discussing the relationship between NERC Organization Standards and Regional Council Standards. The discussion was focused on two areas: 1) Regional differences, where Regional Standards would be become Organization Standards incorporated in NERC Organization Standards, and 2) Regional deference where the members of a Region STF Recommendations would be allowed to follow a Standard that was not included in the NERC Organization Standards. Mr. Hilt reviewed suggested changes to the Organization Standards Manual offered by the Planning Committee and the Market Interface Committee. Scott Moore then moved to approve the Organization Standards Manual as published in the Operating Committee agenda package (that is, without further revision). In the discussion that followed, John Underhill moved to amend the second full paragraph on page 19 of the Organization Standards Manual by striking the sentence In all cases, Regional Standards shall not be inconsistent with or less stringent than Organization Standards and modifying the sentence that followed by adding the phrase inconsistent with or (see insert on the right.) After discussion, the Operating Committee did not approve Mr. Underhill s amendment. It then returned to the discussion of Mr. Moore s motion, which was approved. Chairman Cowbourne asked that the Board of Trustees be made aware of each Standing Committee s discussion of this issue. John Anderson then moved to approve the Standards Task Force s Additional Recommendations. Requested Actions Approve Organization Standards Process Manual as revised If approved, manual will be presented to BOT for approval and implementation at their October 2001 meeting Approve Standards Task Force Additional BOT should commission a review of stakeholder representation and voting procedures within the NERC NERC seek accreditation of the new Organization Standards Process by ANSI and one or more equivalent Canadian standards associations BOT adopt the Reliability and Market Interface Principles as the basis for development of NERC In all cases, Regional standards shall not be inconsistent with or less stringent than NERC Organization Standards. In the event that Regional Requirements are inconsistent with or less stringent than an Organization Standard, then a Regional Difference shall be made part of the NERC Organization Standard. Motion by Mr. Underhill to amend - 6 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 During the Committee s discussion of the Reliability and Market Interface Principles, Gerry Burrows moved to modify Reliability Principle #1 by striking the word prescribed and adding the words as defined in NERC Standards. (See text box at right.) Mr. Burrow s motion to amend was approved with 24 in favor and three opposed. The Operating Committee then returned to Mr. Anderson s main motion, which it approved. Reliability Principle 1 Interconnected bulk electric systems shall be planned and operated in a coordinated manner to perform reliably under normal and prescribed abnormal conditions as defined in NERC Standards. Motion by Mr. Burrows to amend Market Trust Issues Mr. Cauley reviewed the draft Market Trust Issues Concept Paper prepared by the Market Interface Committee s Long-Term Issues Subcommittee. He explained that the Market Interface Committee was not ready to take action on the concept paper at this point. The MIC did, however, take a straw poll asking its members for their opinion on whether the concept paper was: 1) too strong, 2) about right, or 3) too weak. He asked the Operating Committee for a similar straw poll, and the results are recorded in the table on the right. System Redispatch Mr. Cauley presented the System Redispatch Concept that the Market Interface Committee was considering. A copy of his presentation is affixed as Exhibit O. He explained that the System Redispatch Concept is based on MAPP Schedule R. Market Redispatch and System Redispatch differ in that Market Redispatch allows the marketer to select the specific resources that would be used to establish the counter flows necessary to mitigate the constraint. The marketer would not select the specific generators that would be used for a system redispatch. I believe the Market Trust Issues Concept Paper is: Too strong 2 OC Poll About right 26 Too weak 12 Requested MIC Action The MIC recommends that NERC develop and publish an interface to allow the licensed use of IDC information by regional organizations and other value added service providers for market-oriented reliability solutions. The MIC recommends as an initial project in this direction, the approval of the work scope identified in Attachment 11b2 Mr. Cauley explained that the Market Interface Committee was not asking the Operating Committee to approve the development of a System Redispatch scheme, but rather to allow the marketplace to have access to the necessary transaction information from the Interchange Distribution Calculator (or subsequent data source). (See text box at right above). Electronic Scheduling Collaborative NERC s manager of interchange and transmission Gordon Scott noted that the Electronic Scheduling Collaborative would review the various Federal Energy Regulatory Commission orders that were issued the previous day (July 11, 2001) concerning RTO consolidation. He explained that the ESC will be filing recommended business practices with FERC in November 2001 and ask for the Commission s approval. Control Area Criteria Task Force Report MIC Request for system redispatch data interface Task Force chairman Jim Byrd reported that the Control Area Criteria Task Force has completed its assignments and that the Board of Trustees approved the recommended Reliability Model. He then moved to dismiss the Control Area Criteria Task Force, and the Operating Committee approved Mr. Byrd s motion. - 7 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 Continuing Education Units Personnel Subcommittee chairman Robert Thompson reviewed the main points of the Subcommittee s white paper on the Implementation of Continuing Education Units. A copy of his presentation is affixed as Exhibit P. The Personnel Subcommittee is considering implementing a CEU program as an option to the five-year certification exam cycle that is currently in place. Mr. Thompson also explained that the Personnel Subcommittee is conducting a Job Task Analysis to determine the tasks that system operators are currently performing. The Subcommittee is aware that system operator jobs are becoming more and more fragmented as utilities unbundle their operations. Howard Gugel then moved that the Operating Committee authorize the Personnel Subcommittee to post a white paper on the Continuing Education Unit concept. Mr. Gugel further noted in his motion that the Personnel Subcommittee may further refine and expand its white paper before posting for public comment. After discussion, the Operating Committee approved Mr. Gugel s motion. Critical Infrastructure Protection Issues Lou Leffler presented a summary of the Critical Infrastructure Protection Working Group s approach to action and recommended that the Operating Committee allow the CIPWG to post this document as a white paper. A copy of Mr. Leffler s presentation is affixed as Exhibit Q. Vice chairman Fidrych moved to post the white paper for public comment, which the Operating Committee approved. Substitute Members and Proxies The secretary notes the following membership substitutes and proxies at this point in the meeting: Jerry Mosier from NPCC staff replacing Wayne Snowdon Jay Caspray from Southwest Power Pool substituting for Scott Moore Linda Campbell from FRCC staff substituting for Ron Donahey Generation Control and Performance Issues Resources Subcommittee member Terry Bilke reviewed a number of issues with the Operating Committee. A copy of his presentation is affixed as Exhibit R. Appendix 1D, Time Error Procedures After posting for public comment and making the necessary revisions, the Resources Subcommittee brought Version 2 of Appendix 1D to the Operating Committee for ballot. The most significant change in this Appendix is the expansion of the Eastern Interconnection s time error limit from ± 8 seconds to ±10 seconds. In the discussion that followed, some members of the Operating Committee asked whether time error corrections were necessary at all, while others noted that tracking time error was important as a measure of integrated control error. Mr. Bilke explained that widening the time error bandwidth to ±10 seconds was a compromise intended to reduce the number of time error corrections, but not eliminate them. Pat O Loughlin then moved to adopt the new version of Appendix 1D, which the Operating Committee approved. The revised Appendix is affixed as Exhibit S. The NERC staff will submit the Appendix to the Board of Trustees for approval at its October 2001 meeting. - 8 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 Disturbance Control Standard Revision Mr. Bilke noted that the Resources Subcommittee continues to support the 15-minute Disturbance Control Standard, which the Operating Committee had revised from ten minutes on an interim basis in 1999. Jerry Hagge then moved to re-approve the 15-minute Disturbance Control Standard recovery period on an interim basis until the Operating Committee s November 15 16, 2001 meeting. In the discussion that followed, Tim Bush expressed his concern regarding the additional risk to the Interconnection of the 15-minute recovery period as shown in the Resources Subcommittee s analysis. Mr. Bush did not believe the revision was justified. Others pointed out, however, that the absolute risk (once in 4.5 years) was not significant. The Operating Committee then reapproved the 15-minute DCS recovery period. Inadvertent Interchange Standard Don Badley briefly reviewed the status of a joint task group of the Resources Subcommittee and Market Interface Practices Subcommittee charged with developing an Inadvertent Interchange Standard. He noted that the task group would address the apparent inequities between Inadvertent Interchange and energy imbalance requirements. Approval of Interim Policy Changes The Operating Committee re-approved the following Policy revisions on an interim basis: Policy 5, Emergency Operations, Sections B and C Posted for public comment Appendix 9C1, Transmission Loading Relief Procedure, Version 2b Posted for public comment Appendix 3A4, Required Tag Data Reallocation Reference Document Posted as an Appendix for public comment Transactions using Firm Transmission Service during TLR 3b Reference Document Posted as an Appendix for public comment Compliance Program NERC s compliance director David Hilt reviewed the current activities of the NERC Compliance Enforcement Program. He explained that six Security Coordinator audits were scheduled for this year. These included all three Security Coordinators from WSCC, plus ECAR-MECS, MAAC, and MAPP. These audits will be completed by the end of the year. Mr. Hilt also noted that the NERC staff and Security Coordinators continue to review TLR events, and that TLR level 5a and 5b event reports are posted as they are prepared. Use of Operating Guides The item is a follow up to a motion made by former Operating Committee member John Pope at the Committee s March 28 29, 2001 meeting. It dealt with the use of draft documents, which could be categorized as Operating Guides, on a voluntary basis. Mr. Hilt noted that the Standards Task Force has been working on this issue and will provide a recommendation at the November 2001 Operating Committee meeting. - 9 - Final: November 15, 2001
Operating Committee Meeting Minutes July 11 12, 2001 ERCOT Control Area Certification Mr. Hilt noted that he was assembling a review team to certify the new ERCOT Control Area. The review team will consist primarily of personnel from Regions outside of ERCOT Next Meeting The next meeting of the Operating Committee will be held on November 15 16, 2001 in Orlando, Florida. Adjourn There being no further business before the Operating Committee, the meeting was adjourned at 1:36 p.m. Donald M. Benjamin Operating Committee Secretary - 10 - Final: November 15, 2001
North American Electric Reliability Council Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731 TO: PLANNING COMMITTEE OPERATING COMMITTEE MARKET INTERFACE COMMITTEE Dear Members: Planning Committee, Operating Committee, and Market Interface Committee Meetings July 10 12, 2001 May 25, 2001 The Planning Committee (PC), Operating Committee (OC), and Market Interface Committee (MIC) meetings, and the Joint PC/OC/MIC meeting are scheduled, as shown in Attachment A, for July 10 12, 2001 at the Hyatt Regency Indianapolis at State Capitol, One South Capitol Avenue, Indianapolis, Indiana 46204; phone: 317-632-1234, fax: 317-616-6079. The meeting agendas will be e-mailed and posted on the NERC web site on or about June 22, 2001. Dress for all meetings is casual. The PC, OC, and MIC meetings are open; however, committee members and guests MUST register for the July 2001 meetings by completing the registration form (Attachment B). Please return this form to the NERC office by June 15, 2001. The form is also available for downloading from the NERC web site (http://www.nerc.com/) under the Committees heading. The hotel is reserving a block of sleeping rooms for meeting attendees until June 15, 2001 at a rate of $139 single/double occupancy. After this date, the block of rooms will be released and reservations can only be made on a space-available basis. The room rates are effective two days prior to and two days after the meeting dates, if available. To make your room reservation, call the hotel directly at 317-632-1234 or toll free at 800-233-1234 and refer to the North American Electric Reliability Council to get the preferred rate and to ensure your reservation is credited to the NERC room block. A penalty may be charged to NERC if the total rooms blocked for this event are not used. If you use a travel agency for your travel plans, please make sure the agency mentions the North American Electric Reliability Council. Check-in time is 3 p.m. and check-out is noon. The hotel is approximately six miles from the Indianapolis International Airport. Carey Indiana offers shuttle service for approximately $8 per person one way. Call 317-241-7100 to arrange an advanced pick up. Taxis are approximately $17 22. Amtrak connections are located at Union Station, which is just minutes from the hotel. Please contact me if you have any questions. cc: Regional Managers Technical Steering Committee Sincerely, Linda M. Scott Linda M. Scott Meeting Coordinator Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com
N ORTH AMERICAN ELECTRIC RELIABILITY COUNCIL Princeton Forrestal Village, 116-390 Village Boulevard, Princeton, New Jersey 08540-5731 1. Administration Operating Committee Meeting July 11, 2001 9 a.m. 5 p.m. July 12, 2001 8 a.m. 5 p.m. Hyatt Regency Indianapolis at State Capitol Indianapolis, Indiana Agenda a. Arrangements Secretary b. Announcement of Quorum Secretary c. Membership and Guests Secretary d. Approval of Minutes of March 28 29, 2001 Meeting e. Approval of Agenda Chair f. Committee Procedures and Waiver of Ten-day Advance Requirement for Motions Chair g. OC Executive Committee Nominations for 2001 2002 Gerry Burrows h. Operating Committee Task List Secretary 2. Operating Committee Executive Committee Actions Secretary a. E-mail action on Policy 5 and Critical Infrastructure Protection Approach to Action b. May 22, 2001 Conference Call on Projects 3. Process for Selecting Subcommittee Officers and Members Don Benjamin 4. SPP and ECAR Control Area Certification Procedure Dave Hilt 5. Midwest ISO Security Plan Roger Harszy, Dave Zwergel 6. Summer 2001 Operations a. Transfer Studies Bob Cummings b. NERC Summer Assessment Ed Weber 7. Organization Standards a. Organization Process Manual and Standards Task Force Recommendations Dave Hilt, Gerry Cauley b. Operating Policy Measures Dave Hilt c. Standards Transition Task Force Scope and Activities Jim Byrd Phone 609-452-8060 Fax 609-452-9550 URL www.nerc.com
Operating Committee Meeting Agenda July 11 12, 2001 8. Budget 2002 Bob Cummings 9. Policy 3, Interchange Charles Yeung 10. Market Trust Issues Concept Paper Gerry Cauley 11. Congestion Management Gerry Cauley a. System Redispatch Functional Description Concept Paper b. NERC Security Data Interface for Regional Applications c. Need to Know Criteria for Access to NERC Security Data 12. Electronic Scheduling Collaborative Gordon Scott 13. Control Area Criteria Task Force Jim Byrd 14. Continuing Education Units Bob Thompson 15. Generation Control and Performance a. Interconnection Frequency Trends Terry Bilke b. Inadvertent Interchange Standard Don Badley c. Disturbance Control Standard Update Terry Bilke d. Appendix 1D, Time Error Correction Procedure Terry Bilke 16. Critical Infrastructure Protection Approach to Action Lou Leffler 17. Compliance Program Dave Hilt a. Security Coordinator Audits b. TLR Investigations 18. Use of guides on a Temporary Basis Dave Hilt 19. ERCOT Control Area Status Dave Hilt - 2 -
Exhibit C Operating Committee Meeting Attendance July 11 12, 2001 Indianapolis, Indiana Derek R. Cowbourne Vice Chairman Mark Fidrych Chairman William C. Phillips Past Chairman** Voting Members: ECAR Pat O Loughlin Customer John A. Anderson ERCOT Jim Byrd Customer Ryan Kind FRCC Ron Donahey Linda Campbell (for Ron Donahey)** Federal Federal Paul Arnold Van Wardlaw MAAC Bruce Balmat IOU Gerry Burrows MAIN MAPP NPCC SERC SPP Jerry McElyea (for James Fuhrmann) Jerry Hagge Mike Calimano George Bartlett Scott Moore IOU IPP IPP Power Marketer Wally Johnson Paul Barber (for Reem Fahey)* Reem Fahey** Tim Bush Richard Ingersoll WSCC WSCC Canada RRO-East Canada RRO-West Canada Cooperative John Underhill John Powell Wayne Snowdon Doug Cave Michel Armstrong Howard Gugel Power Marketer State/ Municipal State/ Municipal TDU TDU Ken Clark Gayle Mayo Ross Phillips Dave Christiano Steve Wallace Cooperative Ted Adamczyk - 1 -
Non-Voting Members: Regional Staff Observer NARUC Robert Amato (for Gary Gillis) ECAR Tom Kraynak Larry Bugh Regulator Federal Don LeKang FRCC Linda Campbell Edward Scott Regulator-State (Eastern) Howard Tarler MAIN MAPP Larry Kezele Gordon Pietsch NPCC Ed Schwerdt Jerry Mosier SERC Jim Maughn John H. Troha Herbert Boyd Guests Scott Henry Robert Thompson Gary Jackson Andy Rodriquez Ed Weber Terry Bilke Don Badley Dave Zwergel Ed Riley Mark Meyer Paul Barber Paul M. Cafone Tony Jankowski Sasan Mahktari Mike Burks Bruce Mackay Deanna Phillips Paul Liddell Interconnected Operations Services Subcommittee Chairman Personnel Subcommittee Chairman Personnel Subcommittee Transaction Information System Working Group Chairman Reliability Assessment Subcommittee Chairman Resources Subcommittee Resources Subcommittee Midwest ISO California ISO Western Area Power Administration Market Interface Committee Chairman** Market Interface Committee Market Interface Practices Subcommittee Chairman OATI Department of Defense Joint Program Office Bonneville Power Administration Business Power Line Bonneville Power Administration Business Power Line National Grid USA NERC Staff Don Benjamin Dave Hilt Bob Cummings Gordon Scott Tom Vandervort Lou Leffler Gerry Cauley Barbara Bogenrief *July 11 **July 12-2 -
Individual Statements Operating Committee Meeting July 11 12, 2001 Exhibit D None
Minority Opinions Operating Committee Meeting July 11 12, 2001 Exhibit E No minority opinions were offered for the record.
Presentation to the NERC Operating Committee Midwest ISO Regional Transmission Organization Security Plan presented by David Zwergel Manager, Security Coordinaton Midwest ISO Wednesday July 11, 2001 May of 1996 NERC Establishes Security Coordinator Function Requires that every Region, subregion, or inter-regional group establish a Security Coordinator to provide security assessment and emergency operations coordination both within Regions and across Regional boundaries 1
May of 1996 NERC Establishes Security Coordinator Function Requires that each Region develop a security plan to meet NERC Policies, Standards, and Requirements dealing with operational security May of 1996 NERC Establishes Security Coordinator Function Requires that a NERC Security Coordinator must be established & exist under a Regional Security Plan approved by the NERC Operating Committee 2
Midwest Independent Transmission System Operator (MISO) MISO will operate in multiple NERC Regions and will recognize each Region s policies and standards. Midwest Independent Transmission System Operator (MISO) The MISO Security Plan has already received endorsement from the following: ECAR - February 8, 2001 NERC Security Subcommittee - February 9, 2001 MAPP - April 24, 2001 MAIN - April 26, 2001 3
Midwest Independent Transmission System Operator (MISO) Where there are conflicts in the Regional Policies and Standards, MISO will work with the Regions and members on resolving those conflicts. Work to be completed before Day 1 of operation Establish MISO SC Working Group Train MISO SC personnel Train CA personnel Complete the MISO SC Manual Detailed functions Emergency procedures 4
Role of Security Coordinators According to NERC Have all information necessary to monitor the big picture Have ability to assess security of Region or Interconnection Coordinate various emergency control actions Be operational 24 hours per day, seven days per week Role of Security Coordinators According to NERC Have all information necessary to monitor the big picture Have ability to assess security of Region or Interconnection Coordinate various emergency control actions Be operational 24 hours per day, seven days per week MISO will meet each of these requirements... 5
NERC Operating Policy Appendix 9D Security Coordinator Criteria & Functions MISO will achieve compliance with each item in Appendix 9D as specified in the MISO Regional Transmission Organization Security Plan document Security Analysis MISO will be responsible for Security of Transmission System Coordination of Voltage Levels Next Day Operations Planning 6
Security Analysis MISO s computer system & security applications will provide: Power flows Contingency Analyses Voltage Security Assessments Optimization Applications NERC Policy 9 - Section B Current Day Operations- Energy MISO will achieve compliance with each item listed in NERC Policy 9 Section B as specified in the MISO Regional Transmission Organization Security Plan document 7
NERC Policy 9 - Section C Current Day Operations- Transmission MISO will also achieve compliance with each item listed in Section C of NERC Policy 9 as specified in the MISO Regional Transmission Organization Security Plan document MISO Congestion Management Multi-tiered approach to: Enable markets where possible Limit curtailments Provide protection options for both firm and non-firm transmission service 8
Maintenance Coordination The MISO will be responsible for coordinating transmission and generation maintenance as described in NERC Policy 4 and in Appendix E of the MISO Transmission Owners Agreement. NERC Policy #6 Availability of Operating Guides MISO will establish and implement operating procedures to cover normal and abnormal power system conditions 9
NERC Policy #6 Availability of Operating Guides MISO will revise these procedures as appropriate in consultation with affected Owners, Members, and the advisory committee NERC Policy #6 Availability of Operating Guides MISO plans to build a centralized library of operating procedures which will be readily available to all appropriate personnel, and in some cases to the public 10
Functioning As a Single Security Coordination Area MISO Transmission Owner members presently include members of the MAIN, MAPP, & ECAR Regions Functioning As a Single Security Coordination Area To effectively monitor and provide security coordination services, MISO will be divided into security-monitoring areas, and will employ one group of Security Coordinators for each of these areas. 11
Functioning As a Single Security Coordination Area The number of security-monitoring areas and their boundaries will be adjusted As appropriate Functioning As a Single Security Coordination Area The number of security-monitoring areas and their boundaries will be adjusted As new members join the MISO 12
Functioning As a Single Security Coordination Area The number of security-monitoring areas and their boundaries will be adjusted As the MISO agrees to provide security coordination services under contract to non-members Functioning As a Single Security Coordination Area The number of security-monitoring areas and their boundaries will be adjusted As security-monitoring areas are adjusted along logical electrical boundaries 13
Functioning As a Single Security Coordination Area Initially there will be two security areas East Security Area North Security Area And upon successful completion of the merger with MAPPCOR West Security Area Functioning As a Single Security Coordination Area Initially there will be two security areas East Security Area North Security Area And upon successful completion of the merger with MAPPCOR Monitored from Carmel, IN West Security Area 14
Functioning As a Single Security Coordination Area Monitored from St. Paul, MN West Security Area Functioning As a Single Security Coordination Area Security Coordination Staff at both locations will keep in close contact and cross-train from time to time 15
MISO Transmission Owners Alliant Energy New Applicants (Membership Pending) American Transmission Co. Indianapolis Power and Light Central Illinois Light Manitoba Hydro Cinergy Services, Inc Lincoln Electric System Hoosier Energy Cooperative Minnesota Power Wabash Valley Power Sunflower Electric Power Corp. LG&E Energy Utilicorp United Xcel Energy Indiana Municipal Power Agency Northwestern Wisconsin Electric Southern Indiana Gas and Electric Southern Illinois Power Cooperative Otter Tail Power Questions from Don Benjamin and David Cook Q: Any more detail on the MISO s authority? A: The Transmission Owner Agreement is updated periodically with the current version always posted on our website at www.midwestiso.org A statement has been added to the Security Plan directing the reader(s) to our website 16
Questions from Don Benjamin and David Cook Q: MISO will not share information with any wholesale merchant. The NERC Security Coordinator Standards of Conduct defines merchant as both wholesale and retail, so this revision (III.B.6) should be changed A: We agree. The plan has been revised and now states that MISO will not share information with wholesale or retail merchant functions Questions from Don Benjamin and David Cook Q: SC functions, number 3: Should state that the Tariff is consistent with NERC and regional rules A: The Tariff is approved by FERC. While the intention is for the Tariff to be consistent with NERC and regional rules, and the MISO Security Plan is consistent with NERC and regional rules, requirements for the Tariff should not be in the MISO Security Plan 17
Questions from Don Benjamin and David Cook Q: Since the MISO is non-contiguous, what plans and procedures does MISO have in place to deal with this? A: MISO has an Inter-RTO Cooperation Agreement between the Alliance Companies and the Midwest ISO (IRCA). The IRCA calls for implementing procedures and protocols involving: Questions from Don Benjamin and David Cook Multi-RTO Rate IRCA Incremental Pricing Post Transition Rate Data Exchange Shared Infrastructure Operation Planning ATC Coordination Security Coordination Redispatch Sharing Reservations/Schedules TLR Coordination Imbalance Markets Real Time Operating Disputes Day 1 Congestion Management Long Term Congestion Management 18
Questions from Don Benjamin and David Cook As IRCA procedures are executed, they are posted at www.midwestiso.org. In addition to the IRCA, MISO is heavily involved with the Inter-RTO Seams Collaborative. Questions & Comments 19
Congestion Problem Areas Within MISO/ARTO 20
Congestion Problem Areas Within MISO/ARTO 1 Eau Claire-Arpin 345kV Russel-Rockdale 138kV + Paddock -Rockdale 345kV Wempleton-Paddock 345kV Paddock 345kV Xfmr #1 + Paddock -Rockdale 345kV Rocky Run-North Appleton 345kV Albers -Paris 138kV Circuit for loss of Wempleton-Paddock 345kV Circuit Stiles-Amberg 138kV + Morgan-Plains 345kV Green Lake-Roeder 138kV + North Appleton-Rocky Run 345kV Congestion Problem Areas Within MISO/ARTO Bland-Franks 345kV Rush Island-St. Francois 345kV McRedie-Overton 345kV Coffeen-Roxford 345kV 2 21
Congestion Problem Areas Within MISO/ARTO Blue Lick Bullit County 161kV Circuit Paddy s West-Summer Shade 161kV 3 22
Reliability Assessment Subcommittee Issues Ed Weber July 2001 Topics Confidentiality Concerns Status report Ten year assessment report Revised RAS Scope Update on summer conditions to date 1
Status of 10 Year Report All data and Regional self-assessments are in Data being processed In response to BOT request, NERC contracted with consultant to track new merchant generation Regions asked to review consultant list and indicate which projects they included in their IE411 filing. (due July 20) Status of 10 Year Report RAS will use consultant information, EPSA data and Regional feedback to develop expected US future capacity conditions Preliminary analysis indicates capacity margins following same trends as last year s report 2
Status of 10 Year Report Report changes for this year No more Interconnection analysis Similar to seasonal assessments will focus on key Regions WSCC California NPCC New York City SERC Entergy subregion ERCOT Success story to date Status of 10 Year Report Issues Environmental Regulatory/Legislative RTO s Adequacy Benchmarks Distributed Generation Transmission Load Forecasting 3
Status of 10 Year Report On target to complete the report in late August PC approval in early September BOT approval in October Current draft can be made available if PC desires New RAS Scope RAS reformulated by PC All meetings will be closed, members to sign confidentiality agreement Action: Approve new scope with RAS revisions 4
Summer Conditions Summer assessment reports stated: Blackouts in California Tight capacity conditions in Pacific Northwest, New York City and New England ERCOT cut over to single control area in summer something to keep an eye on Update No blackouts in California (yet?) San Onofre 3 June return (~1100 MW) Peak load around 40,000 (47,700 forecast) Good unit performance to date Many new projects delayed, about 1000 MW should be in for July 5
New York City Update All combustion turbines anticipated to be in place soon. Six already operational New England No problems to date Pacific Northwest On track for second worst recorded water year Update ERCOT cut over delayed to July 20. Las Vegas experienced blackouts for about 1 hour on July 2. Demand outstripped capacity. Regional representatives to PC have any further details to offer? 6
Confidentiality Concerns Concerns regarding release of draft assessment reports to entire PC RAS proposal (existing arrangement): PC Executive Committee to review/approve all assessment reports on behalf of PC. PC Exec members to sign confidentiality agreement. 7
Exhibit H to be added at a later date.
NORTHWEST POWER POOL System Conditions Update Paul Arnold July 11, 2001 NWPP THE WATER SITUATION Precipitation -- Columbia Basin NWPP 2 1
THE WATER SITUATION Precipitation -- Snake Basin NWPP 3 2
THE WATER SITUATION Runoff History at The Dalles FFF 170.00 160.00 150.00 140.00 - March Final (58.6 maf) - July preliminary (54.7 maf) Ranked January - July Runoff at The Dalles 1929-2000 130.00 120.00 110.00 100.00 90.00 80.00 70.00 NWPP 60.00 50.00 40.00 6 3
WATER Actual and Expectations NWPP The latest forecast of January through July Volume Runoff at The Dalles dam is 52% of Average (54.7MAF), as compared to the original report of 55% of Average (55MAF). Second lowest water year to be recorded, lowest 1977 (53.8MAF) 7 4
5
REFILL OF RESERVOIRS NWPP As of June 27, 2001, the Coordinated System reservoirs are at approximately 57.5% full based on energy content and operational flexibility. This results in a hole of 21,688 MW-months. Northwest hydro reservoirs are expected to refill to the lowest level seen in recent history. 12 6
THERMAL GENERATION New Additions. Two New Generating Plants Klamath Cogeneration - 485 MW (July, 2001) Rathdrum - 270 MW (August, 2001) Other Multiple 1-2 MW units and larger (fuel oil and gas-fired) NWPP 13 CHANGES To Existing Loads For the month of June, 2001, the area energy and peak loads are 87.1% and 86% of the Pool forecast. NWPP Energy load (temperature adjusted) is 7.5% lower than 2000 1,800~3,300 MW Load Off (Industrial & Irrigation) Two States have appealed to the public for voluntary load reductions. NWPP-wide, ~4% has been achieved. 14 7
SUMMER 2001 Overall Expectations The Northwest will be able to just meet firm load and reserve requirements with no additional margin for the 2001 summer. Exports (if any) to other areas will be limited. NWPP 15 WINTER 2001-2002 Outstanding Issues NWPP Expect load - peak and energy? New Generation? Generation Performances? Reservoir Refill levels? Transmission Constraints? Weather? Imports/Exports? 16 8
NERC Central Repository Standing Committees Meeting July 10-11, 2001 Central Repository Project Overview Single, independent source for data storage including: Security events (East - TLRs & West - USF) All E-tags (with all status messages) System Data Exchange (SDX) database Schedules (OASIS Phase II/E-Scheduling) 1
Purpose & Benefits Fulfill FERC Order 605 requirement for centralized posting of curtailment and interruption data (approved by MIC in 2000) Fulfill desire for marketplace to have one central site for obtaining information (currently stored on multiple sites - if stored at all) - as requested by MIC Provide site for FERC, NERC or DOE to obtain compliance monitoring and reports Purpose & Benefits, cont. Could be used for EMS schedule verification, Security information, curtailment data, E-tag back-up recovery System Data Exchange (SDX) database for IDC and system security analysis Easily expandable to accommodate future central data collection and processing systems 2
Central Repository Questions Can the RTOs do this work instead? Yes. Estimated cost for hardware and software - $250,000 - $500,000 per RTO for a total of $3M -$6M (depending on number of RTOs). Still would require querying multiple sites for information. Will the Repository ever get used? Utilities have already expressed interest in using data for Real-time data verification and information gathering. NERC, FERC and WSCC desire to use it for compliance monitoring. Central Repository Questions Why should NERC build a? Completion of the Transaction Information System NERC compliance monitoring Requested by MIC September 1999 What s to gain for NERC? Provide a central site for data storage Aid in FERC compliance Provide site for compliance monitoring Expandable for future necessary systems 3
Central Repository Questions If expanded in the future, aren t the costs exponentially higher? No. Because of the system architecture chosen, expansion can use: same hardware same licenses software costs would be minimal Central Repository Questions Why store 4 years of data? Could you decrease cost if you only store 1 year of online data and the rest on tape? 4 years was an arbitrarily chosen number Data could be used for modeling If data storage is shortened, only minimal hardware cost savings 4
Central Repository Questions What does my company stand to gain? TP Compliance with FERC order 605 One site for data retrieval Site for historical data for modeling, etc. Is the cost reasonable for a system this size? Yes using the newest in database technologies and hardware Central system cheaper than duplication by 12-18 RTOs Central Repository Questions What are the consequences of not moving forward with this project? Entities would need to provide a repository of the same data to comply with FERC No central site for data retrieval No central site for compliance monitoring SDX would require a separate system 5
Central Repository Questions Is there another was to accomplish these requirements? Add it to the IDC? Add it to the Tagging Authorities? Both the IDC and Tagging Authorities could gather all E-tag data Would not include security event data, interruption logs, SDX data, etc. Future changes for compliance monitoring and reporting would require changes to multiple systems Milestone Schedule May 2001 RFP issued June 2001 Bids Evaluated July 2001 Standing Committee briefing Nov 2001 Standing Committees approval Feb 2002 NERC Board approval; Contract with vendor Summer 2002 Factory testing at vendor; user and administrator training Fall 2002 Deployment (possibly earlier can go online in background) 6
Budget Implications Estimates still being assembled To be included in 2002 as a Pending Project Alternate funding methods to be investigated Where to From Here? Complete cost estimates and cost benefit analysis Complete Standards and Project Implementation Plan Post for Standing Committee review Present to Standing Committees in November for approval 7
E-Tag 1.7 Project NERC Standing Committees Indianapolis, IN July 10-12, 2001 E-Tag Version 1.7 What and Why Major step in improving tagging flexibility & adding long-requested functionality enabled my move to XML Long-requested tagging functions for market First step toward FERC goal of Electronic Scheduling Noted in Industry response to FERC s ANOPR 1
E-Tag Version 1.7 What and Why (cont.) Provide long-requested functions to the market including: Tag corrections PSE tag adjustments Horizontal transmission reservation stacking IDC must be compatible with new data format and functions of E-Tag Version 1.7 E-Tag Version 1.7 What and Why (cont.) Functions of E-Tag 1.7 to support December 2001 RTO scheduling systems Requested by RTO Seams Collaborative One Stop Shopping Group Inter-RTO scheduling systems dependant 2
E-Tag Version 1.7 Features extensible Markup Language (XML) Data Model Profile Descriptions Transmission Stacking - Vertical and Horizontal Corrections by Tag Author Versatile Energy Profile Changes Financial and Physical Path Differentiation Recovery Functions Checkout Functions Project Budget Background Budgeted as Maintenance $50,000 budgeted for tagging-related IDC changes Breath of 2001 revisions (XML) for E-Tag not known at time of budgeting for 2001 $100,000 pending project listed for Electronic Scheduling Magnitude and cost of task warrants separate project approval Vendor estimate of IDC change cost = $500,000 Net budget increase = $450,000 3
Benefit Analysis Most E-Tag 1.7 benefits are to the market due to increased functionality Benefits to system operations in schedule checkout and recovery functions Profile Changes benefit all that use static schedules Benefit Analysis (cont.) Corrections Administrative Savings Assumptions 5 minutes per correction (often longer) 2 party tag (very conservative) $50/hour loaded cost 10% of all tags (923,500 tags in 2000) Savings = $769,583 Benefits to both Market and Operations 4
Benefit Analysis (cont.) Physical Financial Paths Reduces delivery risk by properly structuring information requirements and data entry Reduces legal risk due to explicit separation of title holders from transmission customers Benefit Analysis (cont.) Profile Descriptions Increases market opportunity by allowing for: Capacity schedules Dynamic schedules Reduces delivery risk by streamlining approval process 5
Benefit Analysis (cont.) Corrections Function Reduces delivery risk by eliminating current all-or-nothing approach Transmission Stacking Increases market opportunity by allowing more uses for speculative transmission leftovers Reduces delivery risk by providing proper curtailment priority protection of transactions Benefit Analysis (cont.) Profile Changes Increases market opportunity by allowing flexibility in schedule amounts and rapid changing of those amounts Requests Reduces legal risk by documenting business decisions in greater detail 6
Benefit Analysis (cont.) Operational Benefits Profile Changes Greater efficiencies in managing static schedules Recovery Functions Reduces operational risk by providing mechanisms for disaster recovery Checkout Functions Helps ensure balanced schedules Reduces inadvertent Recommendation Endorse the E-Tag Version 1.7 Project and the attendant changes to the IDC 7
Market Interface Committee Summary of Actions July 10-11, 2001 Gerry Cauley Secretary 1 Membership Issues Formed task group to draft additional interim guidelines on committee member changes Approved MIC Executive Committee MIC Nominating Task Force 2 Interim member changes Started count of TP, TC, and NA for record of meetings 2 1
E-Tag 1.7 Approved E-Tag 1.7 Specification and implementation by October 2001 Concerned with schedule risk/uncertainty Approved granting GPE and LSE the right, but not obligation, to approve tag requests using their resources 3 Organization Standards Process Manual Approved Organization Standards Process Manual Approved 3 recommendations Review representation and voting issues ANSI accreditation of process Adopt Reliability and Market Interface Principles 4 2
Market Interface and Commercial Practices Reviewed paper defining issue and alternatives Conducted poll on 5 alternatives and 4 recommendations Results will be analyzed and distributed Continuing issue for MIC 5 Market Trust Issue (Independence) Discussed paper STINK BOMB!! Could not agree on how to proceed Tabled further work for now 6 3
System Redispatch Approved System Redispatch Concept Paper and support for development of SRD capability Approved preliminary project request for IDC interface to allow regional and vendor applications, such as SRD 7 Security Data Confidentiality Directed CMS work with Security Subcommittee on need to know criteria for security data Confidentiality Agreement Revisions Narrow language to protect from inappropriate uses Require report to NERC and posting of any discretionary disclosures (e.g. during and emergency) Do we need audits? 8 4
Planning Issues Approved PC report on transmission expansion issues Approved memorandum to PC requesting MIC definitive action on new planning standards 9 5
NERC Issues Ranking Sheet Operating Committee July 11 12, 2001 Rate each item on a scale of 1 to 5, with 1 being highest priority to you and 5 being lowest. No. Member Priority Group Priority Issue 1. 1 Standards issues to resolve 2. 2 NERC Interrelationships Core reliability v. commercial NERC top-down development Tool builder or Standards setter Standards process development With RTOs and Regional Councils FERC, Canadian, etc. regulators Independence BOT/Stakeholders/Standing Committees Balanced representation/sectors/governance Budget and Funding 3. 3 Reliability Model and Transition Plan 4. 4 Compliance Program and Enforcement 5. 1 Role of NERC must be much more than just Reliability 6. 2 Get to end-state funding as soon as possible 7. 3 Compliance enforcement and mandatory participation 8. 4 Organization Standards development 9. 5 Transition Plan to adopt new Reliability Model 10. 5 Don t ignore adequacy 11. 5 RTOs and Regional responsibilities and functions 12. 1 Implement Reliability Model + Standards, policies, compliance expectations and measures 13. 2 Roles of NERC, RTO, RRO identified 14. 3 Compliance enforcement 15. 4 Independence 16. 1 ATC Standardization 17. 2 Congestion management and incentives for new transmission 18. 3 Consistent commercial practices - 1 -
No. Member Priority Group Priority Issue 19. 1 NERC s role in the future of business or reliability 20. 2 Cost allocation/expenses and who pays 21. 3 NERC compliance enforcement program as it relates to Standards and Procedures 22. 4 Future role and existence of Regions 23. 5 Independence issues 24. 6 What should NERC s involvement be in developing tools? 25. 7 Reliability Model implementation 26. 1 RTO/ISO representation on NERC Committees and Subcommittees 27. 2 Independence issue settle it now! 28. 3 Need for national legislation for all electric industry entities 29. 4 Classified customers ability to access outage schedule data to help determine their own outage schedules 30. 5 Develop a comprehensive, long range, automation plan. Proactive rather than reactive. 31. 6 Ensure deference to Regional differences 32. 7 Develop series of consequences for those not following policies and procedures 33. 1 Funding, governance, and Committee makeup 34. 2 Security Authority independence 35. 3 NERC involvement in market issues 36. 4 RTO/NERC interface, plus Subregion and Interconnection differences 37. 5 NERC authority 38. 6 Generation resource and transmission capacity adequacy - 2 -
WSCC Requested Revision In all cases, Regional standards shall not be inconsistent with or less stringent than NERC Organization Standards. In the event that Regional requirements are inconsistent with or less stringent than an Organization Standard, then a Regional Difference shall be made part of the NERC Organization Standard.