rcc minutes 20070314 - approved · 2007. 3. 14. · northeast power coordinating council...

September 4, 2007 Members, Reliability Coordinating Committee

and Members, Regional Standards Committee Members, Compliance Committee Members, Task Force Chairs Members, NPCC Inc. Staff Re: Approved Minutes of the March 14, 2007 Reliability Coordinating Committee

(RCC) meeting

Sir / Madam:

Attached are the Minutes of the March 14, 2007 RCC meeting, approved at the May 23, 2007 RCC meeting.

Sincerely,

Phil Fedora

Philip A. Fedora Assistant Vice President, Reliability Services

NORTHEAST POWER COORDINATING COUNCIL

Reliability Coordinating Committee Minutes March 14, 2007

Approved May 23, 2007 2

Mr. Cowbourne called the meeting of the Reliability Coordinating Committee (RCC), held at the Consolidated Edison Company of New York on Wednesday March 14, 2007 to order.

Attendance Officers of the Reliability Coordinating Committee Derek Cowbourne, Chair Independent Electricity System Operator Colin Anderson, Vice Chair Ontario Power Generation, Inc. Henry G. Matsi, Vice Chair New York State Electric & Gas Corporation Transmission Providers Central Hudson Gas & Electric Corporation Thomas Duffy Central Maine Power Company Brian Conroy Consolidated Edison Company Michael Forte of New York, Inc. Hydro One Networks Inc. Ajay Garg Hydro-Québec TransÉnergie Jean-Marie Gagnon Louis Omer Rioux ISO-New England, Inc. Mike Henderson (alternate) Long Island Power Authority Curt Dahl (alternate) National Grid USA Dana Walters New Brunswick Power Transmission Brian Scott Corporation New Brunswick System Operator William K. Marshall New York Independent system Operator (proxy to John Adams) New York Power Authority Gerald LaRose (alternate) Northeast Utilities Douglas S. McCraken Nova Scotia Power Incorporated (proxy to Robert Creighton) Rochester Gas & Electric Corporation (proxy to Henry G. Matsi) The United Illuminating Company Robert Pelligrini Vermont Electric Power Company, Inc. Dean LaForest (by proxy) Transmission Customers Constellation Energy Commodities Glen McCartney (via phone) Group, Inc. Dominion Energy Marketing, Inc. Jalal John Babik Entergy Nuclear Northeast, Inc. John Bonner



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Transmission Customers (continued) FPL Energy, LLC (proxy to Edward A. Schwerdt) Hydro-Québec Distribution Daniel Richard Hydro-Québec Production Andre Cauchon PPL, Energy plus, LLC Joseph Langan (via phone) Public Interest New York State Department Howard Tarler of Public Service NPCC Inc. Jennifer Mattiello Vice President & COO and Treasurer Philip A. Fedora Assistant Vice President of Reliability Services James H. Hartwell Manager, Operations Compliance Brian Hogue Information Management/System Administration Donal Kidney Senior Engineer Quoc Le Manager, Compliance John G. Mosier, Jr. Assistance Vice President, of System Operations Reza Rizvi Engineer, Compliance Frantz Roc Manager, Information Technologies Paul Roman Manager, Operations Planning Edward A. Schwerdt President & CEO Guy Zito (part-time, via phone) Assistant Vice President of Standards Guests Luis Marti Hydro One Networks, Inc. Paul Metsa Chair, CO-12 Working Group Oswald Ortega (part-time, via phone) Northeast Utilities Robert Russo (part-time, via phone) Northeast Utilities Carol Sedewitz Chair, Compliance Monitoring and

Assessment Subcommittee Daniel Soulier Chair, Task Force on Coordination of Operation Phil Tatro Chair, SS-38 Working Group Peter Yost Consolidated Edison Company of New York, Inc. John Vasco Vice Chair, Task Force on System Protection




Quorum Statement Mr. Fedora indicated that a quorum has been achieved, representing 100% participation of both the NPCC Inc. Transmission Provider and Transmission Customer voting classes, through member attendance, proxy or alternate designation.

Antitrust Guidelines for NPCC Meetings Mr. Fedora informed the RCC that the current antitrust laws make it important that meeting participants avoid discussion of topics that could result in charges of anti-competitive behavior, including restraint of trade and conspiracies to monopolize, unfair or deceptive business acts or practices, price discrimination, division of markets, allocation of production, imposition of boycotts and exclusive dealing arrangements. The meeting attendees were advised that during the meeting or during any breaks they should not enter into conversation involving the following topics:

• Your company’s prices for products or services, or the prices charged by your competitors;

• Costs, discounts, terms of sale, profit margins or anything else that might affect prices;

• The resale prices your customers should charge for products you sell them;

• Allocating markets, customers, territories or products with your competitors;

• Limiting production; • Whether or not to deal, or not to deal, with any company; and, • Any competitively sensitive information concerning your company or a

competitor. Mr. Fedora suggested contacting NPCC Inc.’s Assistant Secretary, Andrianne S. Payson at (212) 424-8218 for further information. Mr. Cowbourne asked if there were any changes, amendments, or deletions to be made to the Agenda. He indicated one change in Agenda order - Agenda Item 6.1 – Review of the Richfield January 30th Event - will be scheduled immediately after the Consent Agenda, in order to accommodate travel schedules of the presenters. Upon hearing no other changes, the Reliability Coordinating Committee unanimously approved the Agenda.



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President & CEO Report Mr. Schwerdt reported on the following three topics: NPCC Corporate Strategies The NPCC Inc. and NPCC CBRE Boards, at their respective February 6, 2007 meetings, established the corporate goal of continuing the restructuring of the reliability framework for Northeastern North America by merging the corporations by the end of 2007 into NPCC Inc. the Cross Border Reliability Entity and Reliability Services Corporation for Northeastern, North America. Having established the separation of reliability services from the delegated authorities granted under the Regional Delegation Agreement and the Canadian MOUs, the transition to a more efficient corporate model, i.e., divisions, with separately focused and funded divisions is the next step. This strategy will help simplify a number of aspects within the 2008 Business Plan and Budget. On of the most evident benefits will be in the reliability requirements area, where the objective will be to codify the mapping document approved by the RCC last year through the incorporation of mandatory standards with the more-stringent regional reliability criteria into a series of topic-specific Reliability Requirement Directories that will provide a combination of the structure of measurable compliance elements with the over 42 years of technical expertise contained in the NPCC Criteria, Guidelines and Procedures. Mr. Zito will address these issues in more detail later in the meeting. With respect to the status of the search for a new independent consultant Chair of NPCC, the Search Committee has reviewed a number of viable applications and has established an aggressive schedule to fill the vacancy. If anyone wishes to submit additional nominations for consideration, the form and procedure is available on the NPCC website. In addition, the Boards of both NPCC Inc. and NPCC CBRE have expressed their thanks and best wishes to the outgoing Chair, Mr. Charles Durkin, Jr. NERC & Regulatory Issues FERC is scheduled to act tomorrow to approve the first set of NERC reliability standards for mandatory enforcement, effective June 1, 2007. The expectation is that FERC will act on the Regional Delegation Agreements at its April 2007 meeting. The implementation MOU between NERC, NPCC and the IESO addressing mandatory compliance in Ontario was executed in November 2006 and negotiations with the other Provinces continue.




2008 Business Plan and Budget Development The NERC Board of trustees (BOT) recently met to consider issues raised by NPCC regarding the Business Plan and Budget process and specifically to address concerns regarding content, applicability and allocation issues. A copy of NERC’s 2007 Business Plan was distributed with today’s meeting Agenda, and the latest version of a combined NERC and NPCC schedule for 2008 Business Plan and Budget development, modified at a NERC budgetary meeting yesterday has been distributed to you today. The NERC BOT has committed to a more open and transparent process with regards to its Business Plan and Budget development and further revisions to the schedule should be anticipated as NERC staff incorporates additional stakeholder review steps into the process. These revised schedules will be distributed to you as they become available. Mr. Gagnon asked for more explanation regarding the reasons to merge NPCC Inc. and NPCC CBRE after they were specifically split apart last year. He also asked if the Reliability Requirements Directories were a “done deal”, or if other proposals or alternatives would be entertained. Mr. Schwerdt replied that with respect to the Reliability Requirements Directories, the objective there is to take the mandatory standards, marry them with the more stringent NPCC requirements, so as you move forward in time, you have one set of reliability standards, one set of expectations with regards to what it means to be in compliance in the Northeast. We also bring in the guidelines and the procedures into that documentation, and marry the explanation of how and why you do it, that is within the criteria with the pure listing of statutory requirements that NERC has within its standards, so it makes it not only a combined document but also makes the answer to the question, “Why am I doing this?” that’s contained in the 42 year technical history. With respect to “is it a done deal?” we test marketed this now through two joint chairs meetings – Mr. Zito will be making the proposal later today – we are accepting all input, all comments. The alternative to marrying the two activities is to maintain separate criteria, separate standards, and then to maintain the mapping document in between – that is both ineffective, inefficient and don’t think is a sustainable model going forward basis, but there are no “done deals” there are always issues on the table, always enhancements and improvements as we go along. That’s why we are presenting it here today. With respect to the merging of the two corporations; the very specific and focused reasons why we created initially two separate corporations was number one, first and foremost we have a 42 year history of reliability assurance in the Northeast, we did not want to let anything drop off the table – a strict reading of the US Energy Policy Act would have focused the Regional Entity purely on standards development, standards



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compliance, and an occasional assessment – when we made the decision, the Boards made the decision to create the two corporations there was uncertainty with regards to something we will call reliability services; something in the middle between just the criteria we create and the standards that would be enforceable by FERC through NERC That’s the entire helper function, the reliability assessment function which is the focus of this group. So we offered up for the first budgetary cycle a three part budget –one that was, in a strict reading, a statutory budget, one that was, in a strict reading, a purely regionally focused, and one that could go either way. We didn’t want to lose anything. Now that FERC has ruled on our budget, and the separation has been identified, and has been accepted, now, for efficiency purposes, what we want to do is create divisional separation, rather than corporate separation. It would be a lot easier for those around the table so we wouldn’t have to keep switching ‘on and off’ hats. Without that initial identification of the two specific roles that NPCC regionally plays, my sense, and the sense of the Board, was that we would have lost our more stringent criteria, we would of lost our support for resource adequacy, and would have lost some of what it is we have done for the past 42 years, and that was not an acceptable alternative. Ms. Sedewitz asked if all being under one corporate entity would means there wouldn’t be two Boards anymore – there would only be a single Board, and a single Reliability Coordinating Committee? Mr. Schwerdt replied affirmatively. Mr. Tarler inquired about the voting structure. Mr. Schwerdt replied that the voting structure, because it will need to pass the no one sector can dominate, no two sectors can veto test, we will have sector voting within all of NPCC CBRE, including sector voting here at the RCC as we move forward. The RCC will become a decisional making body within the corporation and as such will have to have sector voting. This would take effect with the merger of the corporation. Mr. Cowbourne added that the RCC today is operating under the rules published for it today – and that there will be no change until further notice.

Chair Report Revised Scope Mr. Cowbourne said that the role of the RCC is spelled out in the revised Scope included in the Agenda package; most recently approved by the former NPCC Executive Committee as part of the 2007 NPCC Business Plan and Budget on September 7, 2006. The RCC is the senior technical committee for NPCC. The primary intention is for




support of NPCC Inc. and its associated criteria; it also extends to NPCC CBRE activities, as well. A revised RCC Scope has been included in the Agenda package, with changes highlighted. The changes reflect the NPCC organizational changes since then and update the responsibilities accordingly. Mr. Cowbourne stated the goal for the RCC members is to review the scope document, to offer comments on it to Mr. Fedora by April11th, in order to approve the revised Scope at the May 23, 2007 meeting. 2007 Activities Mr. Cowbourne stated that although not a work plan, the summary included in the Agenda package represents the RCC activities planned for 2007 that are consistent with the NPCC Inc. Business Plan and the 2007 NPCC Inc. organizational goals. The Reliability Coordinating Committee unanimously endorsed the activities planned for calendar year 2007 as described in the summary provided with the meeting materials, changing the sixth bullet of core reliability functions reading: “Monitor developments at NERC for blackout related recommendations ...” to “ … system event related recommendations …”. Mr. Cowbourne also indicated his desire to develop a draft of a two-year work plan for the RCC, one that takes into account the goals of the corporation. He indicated he would be working with the Vice Chairs, the Task Force and Subcommittee Chairs, and Mr. Schwerdt to identify and extend the RCC activities beyond 2007. He said he plans to present a draft to the RCC for approval at the next meeting. The two-year RCC Work plan would, in turn, guide development of the Task Forces and Subcommittee future activities to support the NPCC objectives. NPCC Inc. Member Website Password Change Mr. Fedora provided the new password for the NPCC Inc. member website, which will be changed on the afternoon of March 30, 2007. The username remains unchanged.

Consent Agenda The Reliability Coordinating Committee unanimously approved the following Consent Agenda items: Minutes of the Meeting of the November 28-28, 2006 The “Draft for Approval” of the minutes of the Reliability Coordinating Committee meeting of November 28-29, 2006.



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Roster Changes The following changes to Task Force and Working Group memberships: Task Force on Infrastructure Security & Technology Mr. Martin Fenland of Hydro-Québec TransÉnergie as the Vice Chairman.

Task Force on System Studies Mr. Michael Falvo succeeds Mr. Danny Fok as a member, both of the Independent

Electric System Operator.

Mr. Brent Oberlin succeeds Mr. Jim Helton as a member, both of ISO-New England, Inc.

Task Force on Coordination of Planning Mr. John Adams of New York Independent System Operator succeeds Mr. Mike

Henderson of ISO New England, Inc. as the Chairman.

Mr. Mike Henderson representing ISO New England, Inc. as the Vice Chairman.

Mr. Reza Rizvi succeeds Mr. Guy Zito as a member, both of Northeast Power Coordinating Council, Inc.

Mr. Hugo Sansoucy succeeds Mr. Roger Lambert as a member, both of Hydro-Québec Production.

Mr. Joe Hipius succeeds Mr. Dana Walters as a member, both of National Grid USA.

Task Force on System Protection Mr. William Shemley representing ISO New England, Inc. as a member.

Ms. Carissa Sedlacek representing ISO New England, Inc. as an alternate member.

CP-8 Working Group Mr. Thong Nguyen-Phat succeeds Mr. Hugo Sansoucy as a member, both of Hydro-

Quebec Production.

CP-11 Working Group Mr. Guy Zito representing Northeast Power Coordinating Council, Inc. as the Chairman. In addition, the following memberships have been designated: Reliability Coordinating Committee Mr. Douglas S. McCracken succeeds Mr. David H. Boguslawski as the member, both of

Northeast Utilities.




Mr. Louis-Omer Rioux of Hydro-Quebec TransÉnergie succeeds Mr. Michel Armstrong, formerly of Hydro-Québec TransÉnergie, as a member. Maritimes Interim Review of Resource Adequacy In accordance with the Guidelines for NPCC Reviews of Resource Adequacy (Document B-8), the Maritimes has presented their 2006 Interim Review of Resource Adequacy report to the Task Force on Coordination of Planning (TFCP). The TFCP reviewed the report and concurred with its main conclusion, that Maritimes meets the NPCC resource adequacy criterion, as planned for years 2007 through 209, and will be in conformance with the NPCC Basic Criteria for Design and Operation of Interconnected Power Systems (Document A-2). Québec Interim Review of Resource Adequacy In accordance with the Guidelines for NPCC Reviews of Resource Adequacy (Document B-8), Québec presented their 2006 Interim Review of Resource Adequacy report to the Task Force on Coordination of Planning (TFCP). The TFCP reviewed the report and concurred with its main conclusion, that Québec meets the NPCC resource adequacy criterion, as planned for years 2007 through 2009, and will be in conformance with the NPCC Basic Criteria for Design and Operation of Interconnected Power Systems (Document A-2). New York Interim Transmission Review In accordance with the Guidelines for NPCC Area Transmission Reviews (Document B-4), the New York ISO presented the New York 2006 Interim Transmission Review to the Task Force on Coordination of Planning (TFCP). The TFCP reviewed the report and concurred with its main conclusion, that the New York bulk power transmission system, as planned for through the year 2011, is judged to be in conformance with the NPCC Basic Criteria for Design and Operation of Interconnected Power Systems (Document A-2). Revised Scope and Terms of Reference for the Inter-Control Area Restoration Coordination (CO-11) Working Group The Task Force on Coordination of Operation (TFCO) revised the scope of activities for the CO-11 Working Group to be consistent with the “Terms of Reference” which govern the TFCO. The revised scope also recommends a simplification of the name of the CO-11 Working Group to the “Restoration Working Group.” Revised Task Force on Systems Studies Scope In accordance with its Work Plan, the Task Force on System Studies revised its existing 2003 Scope.



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Reviews of Major System Disturbances Richview January 30, 2007 Event Mr. Garg introduced Dr. Luis Marti, Manager of Hydro One Networks Inc.’s Special Studies Group. Mr. Garg provided an overview of the January 30, 2007 event at the Richview Transformer Station, located in the west end of Toronto, Ontario. A three-phase fault at the station subsequently led to the loss of approximately 1,500 MW of Ontario load. The resulting voltage decline at the Richview Transformer Station propagated through the grid causing other protection schemes to operate, resulting in approximately 1,500 MW of lost load across southern Ontario. As a consequence of the load loss, intertie flows increased momentarily by 800 MW on the New York interface and by approximately 600 MW on the Michigan interface. No adverse impact was reported by neighboring Reliability Coordinators. A preliminary analysis of the events concluded that a single incident caused the failure of both the main and backup breakers. The phase-to-phase fault resulted from a capacitor failure after energization. After the capacitor breakers failed to interrupt the fault current, the initial phase to phase fault developed into a three-phase-fault. The Transient Recovery Voltage (TRV) exceeded the design levels on the capacitor bank breakers. The high TRV can occur at any location where a current limiting reactor is in series with a high voltage capacitor bank. This arrangement was found at 32 other installations on the Ontario grid. A number of temporary mitigation measures were described, including studying the impact of the operation or misoperation of the protections that occurred and their impact on the system. Hydro One has agreed to notify the Task Force on System Protection of the potential for breaker re-ignition in high voltage capacitor installations with current limiting reactors. Their studies have shown that the failure of the capacitor breakers to extinguish the fault current arc was as a result of excessive Rate of Rise of Recovery Voltage (RRRV) across the breaker contacts caused by the series reactor in the capacitor bank design. Applicable design standards do not discuss this risk.




Mr. Garg indicated that Hydro One will be sharing their experience with the NERC Operating and Planning Committees next week, to alert others to this risk inherent in this type of design. Hydro One requested that the Task Force on Coordination of Operation consider conducting a survey of Transmission Owner members to:

1. Ensure Transmission Owners are aware of this design oversight and the potential risk this issues poses to safety, the equipment and the power system; and,

2. Request Transmission Owners to review their own designs and report back to TFCO, their associated RCs and TOPs whether or not their High Voltage capacitor designs utilize a series reactor and if so are they at risk of excessive RRRV.

Since this phenomenon can occur at any location where a current limiting reactor is in series with a high voltage capacitor bank, the Reliability Coordinating Committee unanimously endorsed Hydro One’s recommendation for the Task Force on Coordination of Operation’s survey of the NPCC Transmission Owners regarding this subject, and subsequent report of its findings, including any mitigation measures or ‘best practices’ that may already be in place at other locations. Mr. Cowbourne indicated that a preliminary report on the incident has been posted on the IESO website (www.ieso.ca).

Reliability Coordinating Committee Actions Review and Approval of Revised Document A-5, Bulk Power System Protection Criteria for Member ballot The proposed revisions to the NPCC Bulk Power System Protection Criteria, (Document A-5) were made in response to a request by the RCC to separate the “should” language to a guide document and to review the provisions for existing facilities in Section 1.1.2, a/k/a “the grandfather clause”. In doing so, the Task Force on System Protection (TFSP) also moved informational non-Criteria language to the associated guide document (new Document B-5). A second Open Process posting of Document A-5 has been conducted to address the comments received from the first posting which was completed on November 16, 2006. A second posting period ended March 12, 2007.



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Mr. Garg suggested documentation of those situations where protection systems do not meet the current criteria of NPCC. Mr. Cowbourne said that the issue is that through Document A-5, as amended, there is some potential for grandfathering some installations that may not meet the criteria, and that may or may not be acceptable in the longer run. However, let’s at least assess the risk from them, before we make any decisions are made - and so the proposal would be to action the TFSP to first catalog those stations that are non-compliant. Mr. Vasco agreed, and said he would bring the task back as an Action Item for the TFSP. He expressed concern regarding the timetable for the completion of the catalog, since given the size of the system and its age; it may take some time to survey each item of the criteria, given the design of the some of the older stations. Mr. Garg suggested leaving the time table for the TFSP to determine, given they represent the experts. He suggested a two stage approach: a high level assessment of the bulk power system stations that at least gives a sense of how many facilities do not comply, then followed by a detailed timetable regarding what’s really required to comply. Mr. Cowbourne asked that the TFSP report back at the next RCC meeting regarding the expected timetable for the two stages. Mr. Gagnon asked for a clarification of Section 1.1.2.1 that states “the result of this assessment should be reported to the appropriate C-22 forms” – what happens after? Will the C-22 forms provide guidance if you are not compliant? Mr. Vasco replied that the TFSP is planning to revise the C-22 forms next week, and will consider how far the assessment should go during their deliberations. Mr. Gagnon asked if the approach taken would basically allow the TFSP to look at the assessment results, then take a position on whether or not something further needs to be done. He said it’s not clear from the criteria what action will or will not be taken. Mr. Vasco replied that the assessment is a procedural item, one that could be included in C-22; any actions plans that come out of it could be presented back to the RCC. Mr. Bonner asked about the process of gathering of this information- would it go through the Transmission Owner’s to the generators who own the transmission facilities, or




through the Areas for the re-verification of meeting the new criteria. He stated that not all of the people that will have to do this are at this meeting. Mr. Vasco replied that the TFSP is just starting to consider the process – at next week’s meeting, once the survey is decided, it should becomes clearer where the information lies. For instance, every Area is represented on the TFSP, so the request can go out to every member that has the affected power facilities. Mr. Cowbourne stated he was comfortable with letting the TFSP decide the best way to proceed. Ms. Sedewitz asked if the assessments would be based on the methodology defined in the proposed A-10 criteria defining the existing Bulk Power System facilities, even if there are no any planned or upcoming upgrades at those locations. Mr. Cowbourne responded that the TFSP was been charged to consider these questions; since they need time to meet to discuss the issues, and bring back a timetable for the next RCC meeting let’s leave it to them. If the A-10 criteria is approved, then that’s what they would follow, and if not, then it’s the existing definition they work with. Mr. Marshall asked about the difference in definition of the Bulk Power System (BPS) that FERC/NERC has (using a standard voltage level) versus that defined by our approach on impact on neighboring systems. What exactly is the status of that at this point in time? Mr. Schwerdt responded that within the United States, the Energy Policy Act created a legal definition of the BPS that exists in time. It is not a technical definition. So from NPCC’s perspective, it needs to be implemented, interpreted and applied within the Northeast. All of the existing NERC standards were approved based on a Bulk Electric System (BES) definition, which is different than the legal definition of the BPS. It has been NPCC’s contention that if you change the applicability of the standard, in fact, you have changed the standard; in other words, you need to go through the standard development and review process and approval by the registered ballot body. Tomorrow FERC is scheduled to act on the first group of NERC standards, and it is anticipated that they will opine on how to apply the legal definition BPS. NPCC’s recommendation to NERC is, that within the Northeast, we accept the legal definition of the BPS, (at least in the United States), but then that implementation of that definition is specifically the reliability based impact based methodology. This approach is not inconsistent with the law, nor inconsistent with NERC’s BES definition. There is nothing in the law that says its 100kV and above, that’s a NERC simplification, so they don’t have to go through, for the rest of the industry, go through the rigors of a reliability based impact test. Our expectation is a methodology, whether its NPCC’s or some consistent methodology,



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going through the rigors a of a reliability impact based test will win out, will actually be useable in the long term for the definition of BPS as it applies in the Northeast. It was also mentioned that the CP-11 Working Group, in reviewing the A-10 criteria, wants to come up with the implementation plan clauses or words for what happens when something becomes classified under the new definition. The focus at NPCC has always been to look immediately at the impact of the bulk power classification on protection schemes, but a lot more goes on when something becomes classified as bulk power. It consideration gets added to the Area reviews, for example. So Document A-5 will have to have something to align to the A-10 definition. Section 1.1.2 talks about categories when actions needs to be taken around changing or recognizing changes or the need for changes to the protection system. In accordance with Document A-10 new classification of a bulk power element would fall under Section 1.1.2.2 except for the fact that it only covers reclassification “due to system changes.” This eliminates the category of an element which is now classified BPS just because of A-2 processes. Those words limit the effectiveness of this clause. The words should be struck either now, or after the A-10 criteria is approved. Mr. Cowbourne reviewed the charge to the Task Force on System Protection to come back to the next RCC meeting with a timetable to document those facilities that do not conform to the Criteria in Document A-5, recognizing the need to incorporate the current definition of the Bulk Power System, and the endorsement of Document A-5 to the membership for ballot with the single edit of the deletion of “due to system changes” in Section 1.1.2.2 – Facility Classification Upgraded to Bulk Power System to read: “These criteria apply to all existing facilities which become classified as bulk power system.due to system changes. A mitigation plan shall be required to bring such a facility into compliance with these criteria.” The Reliability Coordinating Committee unanimously approved the Bulk Power System Protection Criteria, Document A-5, as modified at the meeting, and recommended its submission to the membership of NPCC Inc. for ballot. Review and Approval of New Document B-5, Bulk Power System Protection Guide The draft new NPCC Bulk Power System Protection Guide, Document B-5. was created in response to a request by the RCC to separate the “should” language in the NPCC Bulk Power System Protection Criteria, Document A-5 to a guide document.




The Draft new Document B-5 contains all the language moved from Document A-5. In addition, clarifying language was introduced as highlighted in the text. In the review of A-5, the TFSP has attempted to retain Criteria language for which the requirements can be measured, and migrated guidance from the Criteria document to this B-5 document. In doing so, the TFSP determined that some “shall” language was not measurable and moved the requirements to Document B-5 as a “should”. Draft new Document B-5 was posted in the Open Process in conjunction with the second Open Process posting of Document A-5, which closed on March 12, 2007. Mr. Vasco first indicated a relatively minor revision; in Section 2.0, in the first paragraph under General Guidance, the second sentence should read “The intent of the A-5 criteria is to ensure …”; instead of “ The intent of these criteria …” The idea is to refer back to the criteria that this document supports. A similar construct occurs later in Document B-5 (Section 4.4.8) that refers to “these criteria.” Under Section 2.7, under Analysis of Protection Performance, there is an introductory sentence that should be removed; there is a duplicate statement in Document A-5 that states “Event and fault recording capability shall be provided …” He indicated that this is a “shall” statement, and should correctly be in Document A-5; so all that will remain in this section would be the wording shown in Section 2.7.1 Document B-5, the Bulk Power System Protection Guide, was unanimously approved, as amended, by the Reliability Coordinating Committee. Review and Approval of New Document A-13, Verification of Generator Gross and Net Real Power Capability Criteria for Member ballot Mr. Soulier explained that the Task Force on Coordination of Operation (TFCO) developed a new Document A-13, NPCC Verification of Generator Gross and Net Real Power Capability, to establish minimum criteria through which the gross and net real power capability of a generator may be verified. Document A-13 will update and replace the existing Document B-09, Guide for Rating Generating Capability, to ensure the consistent and accurate modeling of generator information in the various NPCC, Inc. reliability assessments. Further, these criteria have been developed to incorporate the requirements specified in NERC Standard MOD-024-1, “Verification of Generator Gross and Net Real Power Capability.” He also stated that the CO-07 Working Group was greatly aided by the generator community CO-7 was augmented with five generator representatives. In particular, Mr.



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Bonner spearheaded the development of the Document A-13 draft, and the TFCO would like to publicly acknowledge his efforts. In accordance with the procedures of the NPCC Open Process, the document has been posted twice to receive public comment, with all concerns incorporated in the current draft. The TFCO recommends RCC approval of the document. Mr. Marshall noted that Section 3.3 states that the criteria shall apply to Thermal Generators (Section 3.3.1), Internal Combustion Generators and Gas Turbine Generators (Section 3.3.2), and Hydro Generators (Section 3.3.3), everything is clearly worded that you “shall” do something, but for Intermittent Power Resources (Section 3.3.4) it only lists “preferred methods” for determining real power capability. There is no requirement to rate them; why is that the case? Mr. Soulier offered his opinion that those intermittent resources are not taken into account for resource adequacy, so this may explain why there is less stringent requirements. Mr. Bonner (Vice Chair of the CO-07 Working Group) explained the CO-07 Working Group had long conversations concerning intermittent units – a lot of different people model them in different ways in their analysis. This criteria is to meet an existing NERC standard, MOD-024-1. The purpose of MOD-024-1 is to validate your static models for the system, to make sure you have the right inputs. We know he larger units are represented in the static models. However, it was different across Areas how much of the intermittent resources were actually in the static models. So we wanted to make it more flexible for each Areas; rather than requiring each Area to test intermittent generators, they could use historical data, for instance. Since the intermittent models varied across the system, the CO-07 Working Group left more flexibility in the process. Mr. Cowbourne asked if they should at least specify the method used? Mr. Bonner replied they do, if they need to validate the model; however, if it’s not in your model, you don’t have to test it. Mr. Cowbourne also called attention to a typo in Section: 3.3.4 “manufacturer’s data” (missing the apostrophe).




Mr. Cauchon stated that he would like to more precision in the criteria; SCADA data can tell us information regarding the capability of wind power; he recommended that the A-13 document should add more requirements for determining the capability of the wind power facilities. In the future, there will be more interest in a common requirement regarding system peak demand and the corresponding capability of wind power systems. Mr. Bonner indicated that the wording could be made it more restrictive, so if you are modeling intermittent resources, that you do test them or obtain the necessary data. Mr. Marshall shared Mr. Cauchon’s concern; he stated, relative to system size, there is an expectation for a large penetration of wind generation in the Maritime Area, so it’s a real issue for us. He agreed for the need for the SCADA data, the detailed data, and not just a preferred way to look at things. He recommended mandatory requirements for that takes into consideration actual operating system performance. Mr. Garg agreed; if its not required, it will be very hard to get this type of information from the intermittent generator proponents, unless those requirements very clearly in the criteria. Mr. Soulier noted at this time, these sources do not have impact on system reliability. As more and more come in-service, there may be some impact; the criteria requirement associated with those sources would be different than the other generator facilities. He suggested specifically working on criteria related to those sources. Most of Document A-13 addresses controlled sources of power. Wind generation is not a controlled source of power. Mr. Bonner suggested the following wording: “For those areas with intermittent facilities in their system modeling, the real power capability and the net power capability shall be based on the following factors:”, with the various methods listed. Mr. Cowbourne suggested the following wording: “that the real power and net power capability for intermittent resources shall be based upon performance tracking and operating data or manufactures data.” Mr. Cowbourne stated he wanted to raise another issue – In Sections 3.3.1 and 3.3.2 Thermal Generator’s ratings are based upon two consecutive hourly periods; Section 3.3.2 concerns ICUs (which, by the way, also happen to be thermal units). But what about combined cycle units, where you have both the traditional steam unit and the gas turbine unit. Do you base that rating on less than one hour, or on two consecutive hourly periods? The A-13 document is not clear.



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Mr. Cowbourne said that in discussing this with Mr. Soulier prior to the meeting, he was going to propose approving Document A-13 today (unless there are other edits to consider) but charge the TFCO to come back with another revision to address the combined-cycle issue. As a result of the discussion today, we could also ask them to also come back with the wind power intermittent language to address those issues as well. Rather than do it here today at the meeting, an approach that may or may not capture everything that needs to be addressed, the TFCO would be charged to do that in a timely manner. He asked if that approach would satisfy those with the wind power issues. Mr. Walters questioned the value of approving it today, if the confusion is left in the document. Mr. Schwerdt responded he didn’t believe that was the case. There are clarifications that we know we know we want to make around the combined-cycle units and the intermittent sources, there may be other issues; as an initial document, there is value to this. It’s not that we are enhancing an existing document. There is nothing out there now; and this is better than nothing. He argued this is a significant improvement over what most of the industry has. He suggested moving forward with this document while recognizing there are enhancements that we already know we need to make. And there is the charge that goes to the TFCO with this approved document to make those changes post haste. Mr. Walters stated he did not thoroughly understand the implications of approving this, other than for modeling purposes; is there any exposure to getting into a grandfathering situation of accepting a capacity value for a facility now and then turn around and have to change a short time later? He asked for consideration of the financial implications of accepting a number at one point, and then later changing it. Its different if the document is only to be used for modeling purposes, and we decide to change the modeling later. He said having something interim now may require the next version to allow grandfathering. Mr. Cowbourne stated he recognized the concern, and said having the A-13 document in place would get NPCC into compliance with the NERC standard, which is something needed before June 1, 2007. Obtaining membership approval of the revision by May is unlikely, so by approving the document as is we would at least be in compliance while working to resolve the combined-cycle and intermittent resource power issues.




If Document A-13 goes out for approval by the membership, it must be made clear in the correspondence that these two issues will be addressed in a timely manner by the TFCO, so no one is in doubt about what they are approving. Mr. Cauchon said that the assessment of wind capacity also has an impact on the determination of resource adequacy. If there are many MW’s of this type of generation, one would have to carefully monitor what is delivered, and determine what is its associated contribution to resource adequacy. NPCC needs to have very clear language regarding the determination of this type of equipment’s gross real power capability. If we are not clear about that, we should not go ahead with the A-13 document right now. Mr. Marshall agreed. The NBSO already agrees on using the winter capacity rating for its resource adequacy assessments; it’s written into our market rules. And this group has indirectly accepted that, because under today’s RCC Consent Agenda, the RCC just approved the Maritimes interim resource adequacy assessment, which includes the assumed wind capacity credits. So there is a need to have pretty clear criteria for the determination. In response to how long it would take to get the proposed changes into Document A-13, Mr. Soulier questioned if the Task Force or Working Group has the knowledge and expertise for these types of alternatives sources that can be used to develop the writing of those specifications? He didn’t recommend the use the A-13 document for resource adequacy assessments; the A-13 document is just checking that the nameplate rating corresponds to the unit’s output capability. Document A-13 was not meant to be used to assess the resource adequacy for the next 10 years; that’s more of planning criteria that should be developed outside of Document A-13. He asked if the CO-07 Working Group felt they had the sufficient expertise to address the issues. Mr. Bonner replied that the CO-07 Working Group has spent a lot of time on the wind power issue, and determined that testing would not be reasonable approach, which left using either the historical data, or the manufacturer’s information. The concern was also raised for a multi-unit site where perhaps you have 50-60 wind turbines, would you get into a situation where you would have to test each one? Although we think we have enough expertise to work our way through this issue (once the issue is understood) are we willing to accept operational testing? It is still up to the Area (or who ever is running the studies) to determine how much capacity a unit should be credited.



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We have the expertise to know what the units capability is, but to utilize that and do any kind of resource adequacy studies, someone else has to determine how much credit should be allowed to take based on the rating. So we can meet the MOD-024-1 standard requirements, but the information needed for resource adequacy studies wouldn’t come out of that standard. Mr. Cowbourne agreed that the A-13 document is just for the verification of rating, it’s not to be used for planning purposes. He wondered if there were a way to separate the two issues. In other words, deal with the A-13 document in the box that it currently is in, with an approach that would address the other issues raised. So the option would be to approve Document A-13 as it is today, as is, and charge the TFCO to undertake actions to revise it in the short term. Some questioned whether any changes make today would obligate reopening this document to another round of comments in the NPCC Open Process. Mr. Mosier believed it was contrary to the NPCC Open Process to add a new section (for example, concerning combined- cycle units) to a criteria document and not repost it. He stated it would not be in the spirit of the open process. Mr. Marshall again stated that there is not a real requirement under Section 3.3.4, it just lists preferred options. He agreed that you don’t need to do testing of wind turbines; he would just like to see some wording that says that you are going to use performance tracking of wind resources, in combination of manufacturers data or you are going to use operational history. He suggested it might be as simple as that, with the addition of “shall”. Mr. Cowbourne suggested considering saying “for intermittent power resources, manufacture’s data, performance tracking, and historical data shall be used to determine generator or generator Gross real power Capability and Net Real Power Capability.” The suggested edit for Section 3.3.4 is “and operating historical data (delete “or”), shall be used to determine …” “For intermittent power resources (wind, solar, tidal or geo-thermal generators the manufacture’s data, performance tracking and operating historical data shall be used to determine generator or generation facility Gross Real Power Capability and Net Real Power Capability.”




With that edit, Mr. Cowbourne asked the TFCO to think about the matter, and take this issue further, as well as consider the combined cycle issue he raised earlier. The Reliability Coordinating Committee unanimously voted to recommend submission of Document A-13, with the above modification to Section 3.3.4, to the membership of NPCC Inc. for ballot for approval, and charged the Task Force on Coordination of Operation to review the intermittent power resources paragraph, address the combined-cycle issue, and come back to the next Reliability Coordinating Committee meeting with a proposal. Type I SPS#23 – Millstone Severe Line Outage Detection Mr. Adams stated that the Task Force on Coordination of Planning (TFCP) recommends approve the Type I SPS, the Millstone sever Line Outage Detection. The existing Type I SPS is going to continue as a Type I SPS; the main reason for the review is that the infrastructure for the SPS was more than twenty years old, it was getting difficult to get replacement parts, and maintenance was becoming a challenge. The owner, Northeast Utilities, decided to replace the equipment that supported the SPS and in the process they modified the detection scheme. He introduced Mr. McCraken, who provided a high level overview, summarized in the Agenda materials distributed for the meeting. He said the purpose of the Millstone SLOD SPS is to prevent an instability situation on the loss of three of the four output lines from the Millstone station. As Mr. Adams explained, this is an obsolescence issue, the equipment needs to be replaced. Factoring in system changes since the SPS was originally installed in the 1980’s system studies indicate a set-point change from 1,200 MW to 1,650 MW as the threshold for a Unit 3 reactor trip on loss of three lines. The sensing used for this is in-direct sensing; National Grid has indicated they would like to see direct sensing used instead. He indicated that is a future consideration, and was asked to put a time frame around that change. He stated that a traditional nuclear refueling cycle is 18 months; two refueling cycles represents three years. He indicated a commitment to a timeframe no later than 3 ½ years; and that he would inform the RCC if there were any change to that schedule. The Northeast Utilities planning group is continuing to do studies evaluating the double circuit tower contingency which, if possibly could be eliminated, which also would eliminate the need for the Millstone SLOD SPS.



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In closing, he mentioned that all the Task Forces have reviewed this Millstone SLOD upgrade in detail, and all questions have been addressed. The Reliability Coordinating Committee unanimously approved the Type I #23 Millstone SLOD SPS upgrade as presented, with the understanding that the change to direct sensing of the line open condition will be considered for a future modification to be completed no later than 3 ½ years from now. Type I SPS# 119 – NSPI 345 kV Generation Rejection Mr. Adams said this is another Type I SPS; it is an existing SPS being modified to allow for increased transfer requirements. It is located in Nova Scotia, and has followed all Document C-16 procedures for review. The Task Force on Coordination of Planning (TFCP) is recommending that the RCC approve this modification to this SPS. At this point, he introduced Mr. Creighton to provide some highlights and details regarding the specifics of the SPS modifications. Mr. Creighton indicated a summary of the modification has been included in the Agenda package for the meeting. He gave a brief presentation regarding what the SPS is intended to do; and the interfaces that are monitored. The existing SPS has been in service since the 345kV backbone transmission was built in the 1990s. The existing SPS is designed to reject one or two generating units (up to 300 MW) for faults on the 345kV lines between Woodbine and Hopewell (L8004) or between Hopewell and Onslow (L8003). If all lines are in service, SPS #119 is not required for no-fault loss of transmission lines. However, if other transmission lines are out of service, then no-fault loss of L8003 or L8004 can potentially result in thermal overloading of transmission, or separation of eastern parts of the system. To date, internal transfer limits have been reduced with elements out of service to accommodate the next contingency. The proposed modification to SPS #119 will accommodate higher transfers and subsequent tripping of L8003 or L8004 without a fault. Since the system conditions for which this element of SPS#119 is armed require high internal power transfer with an element out of service, it is expected that this SPS will be armed less than 10% of the time. The original application for SPS #119 identified the potential for adverse effects outside the local area for failure to operate when required, and was therefore classed as Type I. Although the impact on the interconnected system for a no-fault line loss of L8003 and




L8004 is less severe than the loss of those lines with a fault, there is still a potential for adverse effects outside Nova Scotia, and therefore SPS#119 will maintain its Type I designation, and the proposed modification will meet the requirements of NPCC A-11 Special Protection Criteria. The Reliability Coordinating Committee approved the Type I SPS# 119 – NSPI 345 kV Generation Rejection, as proposed. NPCC Inc/CBRE Quarterly Compliance Report Ms. Sedewitz reviewed the NPCC Inc./CBRE Quarterly Compliance Report for the period beginning January 1, 2007 and ending February 28, 2007, and noted the following: Ontario reported a failure to meet the Testing Requirements for Critical Components Associated with Key Facilities for 2006. Also, New York reported one Category 3 outage caused by contact with vegetation from outside the right-of-way during the month of January 2007. Category 3 outage is a reportable event but does not constitute a violation to NERC Reliability Standard FAC-003-1, Vegetation Management Program. During this reporting period, the Compliance Monitoring and Assessment Subcommittee (CMAS) also completed the review of probable violations from a NERC Readiness Audit in 2006 and included its findings and recommendations in this report. Additional requirements will be reported on as they are assessed as per the schedule established for the 2007 NPCC Inc/CBRE Compliance Program Implementation Plan. The NPCC Inc/CBRE Quarterly Compliance report was unanimously approved by the Reliability Coordinating Committee. New England 2006 NPCC Inc./CBRE Compliance Review Ms. Sedewitz stated that in accordance with the Review Process for NPCC Reliability Compliance and Enforcement Program (RCEP), Document C-32, a triennial compliance review of the New England Area was conducted on September 19-20, 2006 in Holyoke, MA. The Review Team’s report to the Compliance Monitoring and Assessment Subcommittee (CMAS) concluded that New England demonstrated compliance with all of the NPCC RCEP requirements (CPS1, CPS2, DCS, A2-1, A3-1, A3-2, and A6-1) and associated NERC Reliability Standards. The exceptions are RCEP A4-1 and NERC Standard PRC-008. A Level 2 Non-Compliance (A4-1) is identified due to member participants failure



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to resolve all recognized exceptions by the required due date. (This has been self-reported to NPCC by ISO-NE). The New England 2006 NPCC Inc/CBRE Compliance Review was unanimously approved by the Reliability Coordinating Committee. Maritimes 2006 NPCC Inc./CBRE Compliance Review Ms. Sedewitz stated In accordance with the Review Process for NPCC Reliability Compliance Enforcement Program (RCEP), Document C-32, a triennial compliance review of the Maritimes was conducted on May 22, 2006 in Montreal, Quebec and on June 13-14, 2006 in Fredericton, New Brunswick. The Review Team’s report to the Compliance Monitoring and Assessment Subcommittee (CMAS) concluded that the Maritimes has demonstrated full compliance to all eight NPCC Reliability Compliance and Enforcement Program requirements CPS1, CPS 2, DCS, A2-1, A3-1, A3-2, A4-1, and A6-1 and was also deemed in full compliance with the associated NERC Standards. The Maritimes 2006 NPCC Inc./CBRE Compliance Review was unanimously approved by the Reliability Coordinating Committee. March 29, 2006 NYPA Incident Mr. Soulier reported that the Task Force on Coordination of Operation (TFCO) has taken over the responsibilities of the JWG-3, and is preparing to report on the incident at the next RCC meeting.

Status Reports Summer 2007 Pre-Seasonal Assessments Operating Reliability Assessment Mr. Metsa (CO-12 Chair) said he expected, by the end of the week, to receive all of the write-ups to complete a first draft of the subject report, with submission to the RCC on or about April 20th. The Media Release is planned for May 4th. Mr. Roman said RCC approvals will have to be done via e-mail, given the timing. Mr. Metsa gave the presentation regarding the preliminary results for the Summer of 2007, included in the Agenda package. He also included a summer 2006 historical




review, including a summary of forecast versus actual values for last summer. He said that the net revised margin was what was expected. With respect to the historical winter 2006/2007 review, he noted that January 2007 temperatures were above normal, and that peak loads were not experienced until mid- February, 2007. He also mentioned that during the 2007 winter peak time, Quebec was selling approximately 2,200MW during the peak to New York and New England. He reviewed the Summer 2006 forecast versus the 2007 forecast, noting that the net revised margin is a little lower than forecasted in 2006, but that not all the sales and purchases have been reported at this time. He said the preliminary results indicated a negative resource margin June 2007 for New England, and stated that Greater CT may have insufficient capacity due to transmission constraints. For New York, he expected that the margins will go up in the next draft, once the ICAP purchases are finalized. The New Jersey to Long Island Neptune Project will increase the margin by 660 MW. Ontario shows a net margins of 810 MW. The Maritimes and Quebec areas are winter peaking systems, and show apple net margins for the summer 2007 period, even after taking into account scheduled maintenance. However, not all of this capacity is available, some is bottled in Quebec and the Maritimes due to transmission constraints in the United States. An outage on the Madawaska Quebec to New Brunswick interconnection caused more bottling than expected, but it should be on-line this summer. All four Michigan to Ontario transmission ties are in-service, with the Phase Angle Regulator (PAR) operation like last year, bypassed and only operated off neutral tap in order to present load shedding. New England decommissioned the Phase I (Monroe converter) in summer, since Quebec export goes through Phase II in the summer, this it will not effect the transfer capability; however, it may impact winter New England to Quebec import. New England’s southwest CT situation has improved with the in-service of the Phase I of the 345 kV southwest CT project last October; the problem has shifted to the first contingency concerns; these concerns are expected to be fully settled when Phase II of the 345 kV southwest CT project becomes operational in 2009.



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He reviewed the Ontario transmission upgrades from 2006 continuing into 2007. The recent Richview capacitor problem in Ontario, and the IESO’s contingency plans address it will be reflected in the assessment The New York Neptune cable project is now expected to be in-service by July 15th. Mr. Gagnon added that with the retirement of Monroe facility, there is a feasibility study with National grid to consider connecting Des Canton with the Sandy Pond terminal. Multi-Area Probabilistic Reliability Assessment Mr. Fedora (CP-8 Working Group Chair) presented an overview of the preliminary results for the 2007 Summer Multi-Area Probabilistic Reliability Assessment that was distributed in the Agenda package. He mentioned that the CP-8 Working Group has been charged with doing these probabilistic reliability assessment since 1999; the basic methodology remains the same, however the system representation has been expanded, and the assumptions updated for current load forecast and resource expectations. A Base Case, representing the transmission capability and resources expected to be available for the summer period is modeled, along with a Severe Case that considers delays to transmission and resource projects, reductions in demand-response programs, and scheduled maintenance overruns is also considered. The NPCC areas develop the Base and Severe Case assumptions, which are then reviewed and approved by the task Force on Coordination of Planning. The CP-8 Working Group closely coordinated its efforts with those of the CO-12 Working Group’s study. The General Electric Multi-Area Reliability Simulation program was used to estimate the number of times areas may need to use their operating procedures designed to mitigate capacity deficiencies for the two cases. Mr. Fedora presented an overview of the Base and Severe Case assumptions and the corresponding preliminary results. The preliminary results estimate that only under the extreme load level assumption (the second highest load level, representing a 6% chance of occurrence) coincident with all of the Severe Case conditions materializing simultaneously could New York and to a lesser extent, New England experience a very limited number of times for using their operating procedures in response to a capacity deficiency this summer.




The preliminary results from the expected load (based on the probability weighted average of all seven load levels modeled) did not estimate using any of the operating procedures for either the Base Case or Severe Case conditions modeled. Mr. Fedora also noted that record peak loads were experienced last summer, and were met without the use of the operating procedures, although the areas relied on the activation of their demand-response programs designed for such situations. Unexpected outages occurred and were analyzed after the Summer 2006 assessment was completed. He indicated that the CP-8 Working Group will monitor the situation this summer and be ready to rerun simulations to assess the severity of the situation to as circumstances dictate. In response to several questions regarding the modeling of wind resources, Mr. Fedora indicated that the CP-8 Working Group assumptions for wind resources are consistent with those developed by the NPCC areas and are documented with a description that references the related reports. Assumptions for wind facilities vary for different geographic locations, time of day, and season. Mr. Cowbourne also mentioned that the IESO has a working group dedicated to the investigating wind resource modeling methodologies that is open to any interested party (www.ieso.ca). In closing, Mr. Fedora reviewed the remaining study schedule; RCC review and comment on the Final report will be sought April 5 – 12; the TFCP will finalize the report by April 20th. The Media release is scheduled for May 4th, after the presentation on April 24th to the NPCC Inc. Board of Directors. NPCC Inc./CBRE Reliability Requirements Directories Mr. Zito explained the draft proposal for the new document. The idea of the proposal is to categorize all of the NPCC documents into a number of directories, each corresponding to an existing A Criterion document. The Agenda package for the meeting contains an example of a Regional Reliability Reference Directory structure that would be produced by NPCC staff and given to the individual Task Forces as a starting point for their refinement and completion. The document structure attempts to accomplish a number of objectives, including:

Consolidating all “B” and “C” documents related to the parent “A” Document’s topic, i.e., SPSs, into a single Directory-greatly simplifying searching for



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pertinent info regarding the application of SPS into one document, effectively reducing the number of NPCC documents.

Bringing in the NERC and any applicable Regional Reliability Standard Requirements into the document.

Identifying any more stringent NPCC Inc. Regional Criteria Easing future compliance determinations Clarifying and simplifying cross-reference “mapping” between NPCC

Documentation and NERC Standards Requirements

He indicated his purpose is to introduce this concept to the RCC, and listen to comments and suggestions. Mr. Cowbourne advised Mr. Zito to stay on the phone, but due to the poor quality of the phone line, Mr. Schwerdt will lead the discussion here at the meeting. He noted that the RCC has had a chance to review this document, included the meeting Agenda package. Mr. Soulier said the Task Force on Coordination of Operation (TFCO) discussed the concept at their March 1-2 meeting. The following concerns were raised: 1) who going to do the job? Because the proposal seems to be a tremendous amount of work to rewrite or repackage all the documents, is it the Task Force, the Working Group, is it some additional staff NPCC is going to hire? 2) what will happen with the non mandatory, more stringent NPCC criteria? Would they be replaced by the mandatory NERC standards? Is it valuable to keep the criteria as they are, or to make them move to in the direction to be NERC standards? These are the issues discussed. Mr. Schwerdt addressed each question. First, who is going to be doing the job? We had a brief discussion with the joint chairs with regards to as we move forward with this proposal. The impact it can have on the individual Task Forces that have ownership for the various A documents can be reduced by hiring an outside contractor to do some of the initial work. NPCC utilized retired expert help to create the mapping document, and we would use the same approach here. What we don’t want to do is have NPCC lose ownership of the documents. That is a very sensitive issue so who ever it is that will be providing the ‘horsepower’ will be working under the direction and the technical expertise of the corresponding Task Force. The second question actually gets to the heart of why we are doing this. Why would anyone want to maintain more stringent NPCC criteria in an age of mandatory standards? The first response to that statement is, how much of NPCC criteria is more stringent?




If you recall, the RCC approved the more stringent pieces, and there is a fair amount of the criteria language that is, in, fact duplicative, just said in NPCC’s way because of its history. That can be stripped out, and NPCC hasn’t lost anything at all. So part of this exercise is to find those instances where NPCC says it one way, the NERC mandatory standards say it another way, but they have the same level of stringency. And then adopt the standard language. So that’s a major simplification right there. What you have left are: a) the more stringent requirements, and b) those requirements for which there are no NERC standards, revealing additional NPCC requirements. Right now the Northeast operates under both of those requirements, and it is the recommendation that we continue to operate under both the more specific and more stringent criteria, until such time as the membership wants to withdraws those, because the RCC, the Board, the Task Forces can not change a standard. That’s left to the membership. That will be a continuing responsibility of the membership, to impose upon themselves on a voluntary basis more stringent, reliability requirements from the floor that NERC is going to create across all of North America. The intent of the directories is to simplify what exactly that means. We don’t have to have a set of NPCC criteria relatively unrelated to the standards; they should be tightly married. The objective here is to reduce the confusion, handing back to the member systems the responsibility of the approval of any revised documents. These will be identified; that’s why Mr. Zito did A-11 for the first one. We will maintain the identification in the A series together with all of the NERC standards that go within the A criteria , so that the 1,000 odd requirements that NERC has throughout its standards will be married up into something that is actually usable and user friendly to the Northeast through this approach. Ms. Sedewitz asked couple questions and offered a comment. She wanted to make sure, with the directories going forward, when we have the both the NERC and NPCC criteria basically pulled together into one directory, when do we are go through an open process review? When NERC comes up with new standards that get approved and they get placed directly into our directory, will we somehow do an open process of our own criteria on taking out what was in them? After you get it in place the first time, how will we be using it, going forward with our own criteria documents? Mr. Schwerdt responded that the maintenance of this will be actually be rather simple, the NERC standards that are listed are listed there for the convenience of the Northeast, to



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bring together our collective understanding of reliability requirements but literally, there approval or the approval process of those specific requirements will be a NERC issue. Once they are approved, they will be automatically cycled into the NPCC directories without any additional requirements on behalf of NPCC. The ownership of the more specific and more stringent criteria, as indicated by the example, that will still be subject to NPCC members’ system vote. And it will make your job in terms of compliance monitoring that mush easier. Ms. Sedewitz also commented with respect to defined terms (new since the joint chairs call, having that section called defined terms), we will probably have to make it clear that it’s a defined term within NPCC or its a defined term on an ERO standard when we are looking at that so we understand which way its applied. Mr. Schwerdt replied that was a great input; any term that we need to define because of our more specific requirements should literally be in the subset of the document that is clearly identifiable with regards to NPCC. We are not a liberty to define terms for NERC (those come along with the standards) so that’s a great addition to the document layout. Mr. Gagnon asked a question about the directory – would it be possible, before choosing the directory approach, to also propose different methods that you have been analyzed to basically do the same job? After review, then maybe decide on the directory. Now we are going into the directory process exclusively - but – we haven’t seen other proposals on the table, or considered pros and cons of alternative approaches. We have one method that has been proposed, but we are not really sure if it’s the best way to do it, because we haven’t seen comparison between other methods. For example, it seems that WECC is doing it completely differently than NPCC by going through their specific standards and going through NERC as regional standards. That’s another way to do it. Let the NERC standards stand as they are, and then whatever you want to add to it , you could input it into NERC standard as a regional difference, or input it into the NERC regional standards. For me it keeps it a little simpler than trying to put everything in one document and then follow whatever revisions there is in one or the other document. It not clear to me that we are really putting together a process that is simple and necessarily helpful or more efficient. There will be a lot of effort putting that together and by the time we do it maybe NERC will have already gone through a cycle of




revision. I am not really sure (this is my own opinion -not necessarily TransEnergie’s opinion), but looking at this one particular proposal for SPS wasn’t convinced we were putting something together simple at this point. Why is NPCC taking the directory route when there are other proposals in other regions? That’s the question. Mr. Schwerdt replied that are there other ways we could address the issue at hand – we could clearly continue with the status quo where we maintain separate criteria and NERC goes ahead and creates additional standards. The issue with regards to that, as this group has already addressed is the need to perform a mapping exercise so we know how, as we operate and plan the system how the two separate documentations live side by side it’s a different way of saying it or actually a different level of requirement. The maintenance of that activity moving forward has a cost in terms of activity around this table and in terms of its application within the member systems. The concern is that as the NERC standards process comes to cycle through, that becomes an un-maintainable model (keeping that mapping document up to date). And the we run into the problem of the compliance associated with keeping two separate sets of books. Is this the only way to do it, arguably, no. Is it the best way to do it? We have thought about this internally, with the Board, in some joint Task Force meetings. We want you to ‘kick these tires’. This is not the first run we’ve made; as a Region of incorporating NERC documentation. There was an effort before the NERC standards began to move NPCC criteria in the direction of NERC operating and planning criteria, because those were what we thought were going to rule the industry. We took a test run at that, and backed off because even at that point we sensed too much fluidity in the NERC process for us to do a wholesale change of criteria to what was then the NERC operating and planning criteria. But now, based on the mandatory requirements, based on the FERC and potential Canadian Provincial support for the standards, the standards have a much more likelihood of surviving, of being at being at a level where it is appropriate for us to begin the process of incorporating our requirements into standard language. The WECC issue is the following– they have unique standards, the use them in their RMS program, have had mandatory compliance, have already had them reviewed and approved by FERC. None of those are descriptors of the NPCC criteria. We do not have monetary sanctions on the NPCC criteria. Any one around the table is eligible to propose any one of the criteria to be made into a regional standard, with the recognition that it



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goes through an open process. We can create a regional standard through our open process, and that would have the impact of transforming all or any part of NPCC criteria into mandatory standards within the United States with up to a million dollars a day monetary penalties. It is not the suggestion that we go in that direction with these directories. But we have to do something with the standards and criteria that tie them together. Action on a directory does not preclude us from making separate standards decisions on any part of the criteria that collectively we in the Northeast believe that we want to have mandatory standards on. Now, recognizing within the United States that there is a restriction; within the United States law, both NERC and FERC are forbidden to create any resource adequacy standards, so those would always have to be criteria. LOLE cannot be a NERC standard, as an example. That’s the thought process that we have gone through to get us to this point. The reason to bring it hear today to the RCC in the stage is for you all to ‘kick the tires’, and tell us your thoughts, are there is any enhancements? If you are going to use a defined term, put in there so it’s clearly an NPCC issue. Are their other enhancements? Is there a fundamental flaw? We have test marketed this any number of places, and have not yet found a fundamental flaw. But we are prepared to find that, if in fact there is one. Mr. Bonner said if we don’t meet NERC standards, then we are subject to civil penalties (in the US); above that, we have NPCC criteria that may not be subject to civil penalties, (but under the current sanction process), unless NPCC decided to provide these standards to FERC and have them approved by FERC. Mr. Schwerdt stated before NPCC would decide to do that, it would have to go through a separate open process, on the CBRE side, it would have to be voted on by the NPCC CBRE members and sent to the NERC BOT , have it reviewed by the NERC BOT. It is actually the NERC BOT that sends it along to FERC. But we are capable of doing that at any point in time for any reliability requirement that the membership would want to offer up. Mr. Babik suggested the following an enhancement for the NPCC criteria. At Dominion we are dealing not only with the NERC standards, we are dealing with four regions. Each region is going to draft there own standards, and the way they are numbering the




standards. The MRO or FRCC would have the NERC standard numbered with the region identification tacked on – for example, NPCC –MOD-024-1. For the purpose of simplicity it would make my job much easier to track these standards through the region this way, instead of me knowing NPCC as being A-11 or A-8. Would like to get feedback on this approach - would this be a big change for this region to do? Mr. Cowbourne replied that actually its not a bad idea, but maybe its something the Regional Managers might want to discuss; if what we are trying to do in North America is trying to get a consistent set of standards across the eastern interconnection, for example, then an approach like that, adopted by all regions in the eastern interconnection would make the comparison that much easier. Mr. Zito stated the regional reliability standard working group we is presently trying to standardize on the numbering of the standards, so, going forward, it will clearer and more consistent as you look from region to region. Mr. Babik asked if the RCC was the right place to decide on this approach for NPCC. Mr. Schwerdt stated that in the development of regional standards, filed with FERC as a part of our Regional Delegation Agreement, is a regional standard development process, exactly as you described; if we developed regional standards, we would number it exactly like the MRO or FRCC would. It would be an identified regional standard. What the directory does it brings together in a group that’s consistent with what the membership knows today about the A-11document. It will group, without changing them, separate NERC standards that are potentially unrelated, because some of the MODs and PRCs actually are all around a specific topic, that’s why we refer to them as specific topic directories. If you look at some of them, we have to pull from different parts and pieces of the NERC standards family in order to bring together all of the requirements you would need to deal with for a specific topic, like system protection. Or any of the other A level criteria. It’s a different way of grouping them, but it doesn’t change your obligation in terms of a multi-regional player, in terms of what standards you would have to adhere to. Mr. Babik said he was looking for consistency all way around, in order to make someone who has to deal with more than one region job much easier, so they are dealing with the same numbering, so they know what they are dealing with, and its not something different.



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Mr. Cowbourne said their is merit in that, and as Mr. Zito indicated, this is a thought that is being pursued. The RCC doesn’t have to take any action on that, because we are in the early stages of a work in progress, but it is something to keep in mind as we develop this concept. Mr. Cowbourne noted that what we have in the meeting Agenda package today is the proposed format for a directory for SPS. What is the proposal - is it that this will be pursued as a pilot, the first one, learn the lessons out of that, and then tackle the others, or do we set off on all of them in parallel? Mr. Schwerdt suggested a little of both approaches. We want to move forward with this so that we learn through a complete process and we on staff will take the assignment to do some of the back room work and the bookkeeping in order to be able to set up how the other directories might look. At the point that we are convinced that in fact, this is the way we should go, we can take it to the owning Task Forces with a proposal, (having gone through one) and an estimation of a schedule. We are not going to do all of them at once, and burden the RCC and all of the Task Forces. We would also have an estimation of the manpower requirements we might have to contract for in order to meet the Task Force schedules. Mr. Babik said as NERC adopts the Compliance Data Management System (CDMS), they are adopting the standard numbering convention previously described for the regions. Will NPCC accept that process or not, as far as the CDMS is concerned? Mr. Schwerdt responded that the CDMS is a specific, on-line computer management system developed by the MRO to address their compliance data needs. They have also leased that to ReliabilityFirst. NPCC has seen multiple presentations on it; we are also reviewing the SERC system , some software developed by Guidance. The issue is that none of the software packages are consistent with the filed compliance program that NERC has submitted to FERC. Our issue is, if we are going to jump, would like to jump on the program that is easiest to adapt to the uniform compliance monitoring and enforcement program. The fact that NERC is using an overlay of the CDMS to provide summary data to the NERC BOT, both the SERC and other programs would actually have feeds into that. Ms. Sedewitz asked if we should we expect for the next RCC meeting that would there be a schedule you would be coming forward with regarding how long it will take to put directories together, a defined process, a two year process, a three year process, or




whatever it is going to be. Just trying to understand what we may be looking at, moving forward, from the compliance/CMAS perspective. Mr. Schwerdt replied that a schedule would be presented at the next RCC meeting. Mr. Cowbourne asked the RCC to get comments to Mr. Zito as soon as possible, on the format and the process being proposed here. In addition to the comments already received, the RCC is charging NPCC staff in general, and Mr. Zito in particular, to bring not only a plan to the next RCC meeting, but a record of the comments received and how the comments have been addressed (much as you would deal with comments received on a criteria being proposed, so we get an open process type approach to this). Think in that way we will be better able to satisfy peoples concerns. NPCC CBRE Review of NERC Reliability Standards Mr. Cowbourne referred the RCC to the report distributed in the Agenda package. Since the last RCC meeting, the CP-9 Working Group has been involved primarily in the following issues;

Finalize and file the NPCC Regional Standards Development Procedure with the Regional Delegation Agreement.

Coordinate issues and develop Ballot Recommendations for the BAL-003 through BAL-007 Balancing standards. Develop Ballot recommendations on Facility Ratings Standards-coordinating

response to the Category C issue on evaluating credible multiple contingencies when determining System Operating Limits (SOL). Develop draft SAR to submit to NERC.

Coordinating and commenting on revisions to the Reliability Standards Process Manual and develop ballot recommendation

Coordinating and commenting on the ATC/TTC/CBM/TRM Standards and review of FERC Rule 890

Coordinating, commenting and recommending ballot position on the Version 1 Violation Risk Factor set.

Document A-10, Classification of Bulk Power System Elements Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. CP-11, a working group under the Task Force of Coordination of Planning, has developed the subject draft A-10 document. The document has gone through three open process postings, the most recent of these ended on January 8, 2007. CP-11 met on February 12, 2007 and the document is currently under revision to address the comments submitted.



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In addition a request was made to develop an implementation plan which is being developed along with the response to the comments submitted during the last posting. The document will be sent to the task forces for their recommendation and then will be brought before the RCC at their next meeting for consideration and approval. Document A-15, Disturbance Monitoring Equipment Criteria Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. The Task Force on System Protection (TFSP) has developed a new document NPCC Disturbance Monitoring Equipment Criteria, Document A-15 and has posted it in the NPCC Open Process for comments through March 12, 2007. Comments received in the Open Process will be addressed by the TFSP at its meeting on March 20-22, 2007. Document A-3, Emergency Operating Criteria Mr. Soulier reported that the deadline for DocumentA-3 comments was March 5, 2007; the Task Force on Coordination of Operation (TFCO) met on March 2, so, as usual, the comments came on the last day, and the TFCO did not have the chance to review the comments. The main comments concerned the overlap between manual load shedding and emergency load shedding requirements. The old language said it “should” have limited overlap between the two, and “should” be, as far as practically possible. The first attempt was to move the wording to “shall”. It was also suggested that it would be a good practice, instead, and move to a “C” document. The TFCO received a comment that if you remove the language from the A-3 document, you need to present the “C” document at the same time. However, it is not an obligation to present the companion “C” document with the referencing A document. Mr. Cowbourne asked if Document A-3 (alone) would be ready for the next RCC meeting. Mr. Soulier replied it would, if the companion “C” document is not required to be available at the same time. Mr. Cowbourne replied that if the RCC approves the “A” document, it should drive what’s to be contained in the corresponding “C” document. Document A-6, Operating Reserve Criteria Mr. Soulier stated the Task Force on Coordination of Operation (TFCO) received a comment on the last day of the comment period. The change in DocumentA-6 is to allow




the dispatchable load within the synchronous reserve definition and the comment was for the system reliability of the load shedding, if you call disptachable load as synchronous reserve, it should be maintained for a minimum time, either one hour or four hours. The actual proposal is does not addressing the required minimum time. It has to be clarified. To accept load management to be in the synchronous reserve, you have to provide the requirement for the duration of the load management. The TFCO will have to repost the document, so it will not be able to present Document A-6 at the next RCC meeting. Document A-12, System Restoration Criteria Mr. Soulier explained the issue was with the, the Basic Minimum Power System (BMPS) definition – the concern is to define the key facilities list which is normally defined by the BMPS definition, which is not clear at this time. The proposal that the Task Force on Coordination of Operation (TFCO) voted on was to include in the key facilities list a path from the blackstart capability to the interconnection, and also include, in the key facilities list a path from the blackstart capability to the nuclear unit power supply. In addition, the BMPS consisting of the blackstart capability plus one line plus the ability to synchronize it with the rest of the system. The key facilities list includes a path from that BMPS to the Bulk Power System interconnection. BMPS also extends to the auxiliary power supply for the nuclear units, which fulfills a NERC requirement. The TFCO directed the CO-11 Working Group to revise the Document A-12 with those changes; if TFCO agrees with the changes, the document will have to be reported, and thus will not be ready in time for the next RCC meeting. NPCC Inc.CBRE 2007 Compliance Implementation Plan Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. Ms. Sedewitz said the report tells you what you need to be in compliance with, for RCEP, a couple of NRAP items, for 2007 and CBRE compliance, and the NERC standards when they become mandatory June 1st (they are effective now). Some things will come out of our programs once the NERC programs become mandatory.



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Mr. Cowbourne asked if working from a June 1st date when compliance to the NERC standards become mandatory (which we are expecting FERC to endorse tomorrow) has NPCC have everything in place and ready for that June 1st deadline? Ms. Sedewitz replied affirmatively. Registration of Entities Responsible for Complying with NERC and Regional Reliability Standards Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. Mr. Le added that a number of entities didn’t respond to the notification survey, requiring additional follow up. In response to a question, he said he would like everyone to respond to the survey. The information is needed to determine if you need to be registered or not, according to the NERC registration criteria, version 3. NPCC Inc. – Canadian Implementation Agreements Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. The letter summarizes the status of the development of the Memorandum of Understanding/Agreement that commits the Canadian provinces to the NERC Reliability Standards, NPCC CBRE Regional Standards, NPCC Inc. Criteria and compliance with those standards and criteria, including reliability assessments, compliance audits, and readiness assessments. Document A-08, NPCC Inc. Reliability Compliance and Enforcement Program Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. Ms. Sedewitz said the cover letter describes what was exactly changed in the A-08 document. Document A-08 will be posted in the NPCC Open Process for comment and will be back for approval at the next RCC meeting. Document B-22, Guidelines of Implementation of NPCC Inc. Reliability Compliance and Enforcement Program Mr. Cowbourne referred the RCC to the material distributed in the Agenda package.

Task Force Activities Beyond Zone 3 Review Mr. Cowbourne referred the RCC to the material distributed in the Agenda package.




Mr. Soulier inquired about the status of the report, needed for the JWG3 analysis of the March 29, 2006 NYPA incident. Mr. Vasco responded he would inform the Task Force on System Protection. Unit Governing Response Survey Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. Underfrequency Load Shedding Program Review Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. Mr. Anderson asked Mr. Tatro to outline the steps going forward on this activity; is additional work required? Mr. Tatro provided the following summary. The SS-38 Working Group completed a parametric analysis looked at forming the islands a number of ways, by disturbance severity and islanding sequence, based on what’s prescribed in the A-3 criteria. For this parametric analysis, we assumed all the generation conforms to the specified load shedding requirements. In the last assessment, in some of the islands, the frequency decline was arrested at 58 hertz; now, in some of the islands, we see the frequency dropping down as low as 57.5 hertz. In Ontario, the frequency is arrested prior to 58 hertz, but doesn’t recover as prescribed by the criteria. The S-38 Working Group is looking at scenario cases now adding back the system protection modeling to see if the islands survive. We are also modeling the underfrequency relays on the load side of a motor-generator set at the nuclear units, to do a better assessment of what the impacts will be. As a result, we have found that eventually the critical load (for a 25% deficiency) sees the same frequency and tracks the actual system frequency. These are the analyses we need to finish up; we are planning to have a report for your approval at the next RCC meeting. The report will be an assessment of the existing system, And if it shows, as we are expecting, that modifications to the existing system are required, then that would be something for RCC to direct , at that time, for addition analysis, for us to then go back propose what types of modifications are needed to resolve these deficiencies. The SS-38 Working Group would put together several options, vetted through the Task Forces, and brought back to the RCC sometime later this year.



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Mr. Soulier stated that this will mean a revision of Document A-3. Mr. Cowbourne responded that doesn’t stop the Task Force on Coordination of Operation from bringing the A-3 document forward, as now revised, for consideration at the next RCC meeting. Blackout Study Recommendation Mr. Cowbourne referred the RCC to the material distributed in the Agenda package. He said, under Rec 2.a, that the RCC asked for a follow up with RFC and First Energy to try to get this achieved earlier than 2008, and asked for report on that effort. Mr. Le responded that he contacted First energy and NYSG&E to arrange a meeting to discuss expediting the work. He indicated he will be coordinating with TFSS, TFSP and SS-38 and will report back the progress at the next RCC meeting. 2007-2008 Work Plan Progress Mr. Cowbourne asked if there was anything to add to the material distributed in the Agenda package. Mr. Soulier responded that the Task Force on Coordination of Operation are posting a new C documents on the TTC/ATC process. NPCC Reliability Assessment Program (NRAP) Status Report Mr. Fedora said that the NPCC Reliability Assessment Program Summary Report has been updated and distributed in the meeting materials. The full updated NRAP Status Report has also been posted in the Current Year NRAP folder on the NPCC Home Page (http://www.npcc.org/NRAP.asp?Folder=CurrentYear).

Informational Items Summary of NPCC Inc./CBRE 2006 Compliance Program Mr. Cowbourne referred to the report distributed in the Agenda package. The report, developed by the Compliance Monitoring and Assessment Subcommittee (CMAS), summarizes the result of the NPCC Inc/CBRE Compliance Program in 2006. This report and the response to questionnaire on the 2006 NERC Compliance Enforcement Program have been sent to NERC. As shown in the report, NPCC had a very successful compliance year and has fulfilled all of the requirements of compliance assessment and monitoring for both its own requirements and for NERC.




2007 NPCC Inc./CBRE Compliance Workshop Mr. Le reported that the 2007 NPCC Inc./CBRE Compliance Workshop is scheduled for April 25, 2007 at the State Room, Albany, New York. The Workshop will provide participants with an update on this year’s compliance program, including discussion of the results of registration, the audit program this year, the details of the implementation of the uniform NERC compliance monitoring and enforcement program, and go over some examples of simulated financial penalties, as well as presenting the on-line application for reporting compliance and tracking. He encouraged everyone to attend the Workshop. Revised Document C-32, Review Process for NPCC Inc. Reliability Compliance Enforcement Program Mr. Cowbourne referred to the material distributed in the Agenda package. In conjunction with the transition plan to implement the NPCC Inc. compliance program independent of the NERC compliance program, CMAS developed the draft revisions to the Review Process for NPCC Inc. Reliability Compliance Enforcement Program, Document C-32. Revised Document C-15, Procedures for Solar Magnetic Disturbances which Affect Electric Power Systems Mr. Soulier reported that the Task Force on Coordination of Operation, in consultation with the Task Force on System Protection, removed some unnecessary requirements related to HVDC operation in Document C-15. Revised Document C-35, Inter-Area Power System Restoration Procedure Mr. Mosier reported that Document C-35 has been revised and reissued; the only change was in Appendix B for New England, to reflect a corresponding change in New England’s internal restoration plan. New Document C-40, Procedures for Inter-Area Voltage Control Mr. Soulier mentioned he had previously reported on the status of Document C-40. Eastern Interconnection Reliability Assessment Group (ERAG) and Reliability First Mr. Cowbourne referred to the letter distributed in the Agenda package that summarizes the recent activity. NPCC Summer Assessment Status Mr. Fedora indicated this has been covered previously in the meeting.



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NERC Highlights and Agenda Items

NERC Board of Trustees/Member Representatives Committee Mr. Schwerdt said that a summary of the NPCC Boards input to the NERC Board of Trustees (BOT) has been included in the Agenda package. He mentioned that there was a special meeting held of the NERC BOT’s Finance and Audit Committee that was in direct response to NPCC’s first policy input. With regard to the NERC standing Committee Charters, the NERC BOT, thanks to NPCC comments and others comments, deferred approval of all of the NERC Standing Committee Charters until a future BOT meeting so that they could incorporate readiness evaluation into the Operating Committee Charter, and will go to the Operating Committee for vote next week. And lastly, with regards to reliability standards, version three of the Functional Model was approved by the NERC BOT. Acting on the unanimous vote of the Member Representatives Committee, and consistent with NPCC’s input, NERC has filed with FERC a request for clarification, or, in the alternate, rehearing of the issues associated with the NERC Reliability Standards and the violation risk factors. Operating Committee (OC) Mr. Mosier reported that, as mentioned by Mr. Schwerdt, the readiness evaluation program will be added to the Operating Committee Charter which will be put to the Operating Committee next week for vote; this will bring this activity as a program under the Operating Committee, no longer a compliance activity of NERC. The Guidelines for the Review of the Regional Reliability Plans will be presented by the Operating Reliability Subcommittee for approval; this will formalize the process for approving both a Regional Reliability Plan, and if an entity so chooses, the Reliability Coordinator Plan. There will also be a continuation of a discussion that began at the December meeting in which the implementation and the understanding of the Interconnection Reliability Operating Limits (IROL) and the SOL (System Operating Limits) will be discussed in an open roundtable of the Operating Committee.




Planning Committee (PC) Mr. Fedora highlighted the following three items to be discussed at the Planning Committee. The first is a report from the so-called Philosophical team, a draft of discussion materials regarding what constitutes an adequate bulk power system, how do we know when we have achieved one, and how can we be assured that the systems being planned are being appropriately coordinated, so that they will be adequate. Mr. Garg represents NPCC on that philosophical team; please contact him if you have any comments or questions. The second item is the proposal for of a transmission availability data system (TADS), they distributed an interim report from their Task Force, which makes a couple of recommendations for collecting, at the NERC level, transmission outage information. They believe the greatest use for this data would be for outage cause analysis and outage event analysis. Right now this is in the context of a voluntary requirement, in the United States, the DOE EIA-411 requirements have recently included requirements on reporting transmission outage information. Moving forward in 2008, they would be seeking this to be a requirement under a future NERC standard. Mr. Gagnon is the Chairman of this group; if you have any comments or questions, please contact him. Finally, there is a NERC staff white paper regarding the justification for a NERC resource adequacy model, which consists of a proposal by NERC to marry the aspects of production costing modeling simulation (including the incorporation of a DC power flow to model transmission constraints) with probabilistic reliability assessment techniques, creating a new model that would develop Loss of Load Expectation (LOLE) indices. This new model has been proposed to be utilized for future NERC Reliability Assessment Subcommittee resource adequacy assessments. In general, there seems to be little support for this model development, not only in NPCC, but across North America. The white paper has been sent to both the CP-8 Working Group and the Task Force on Coordination of Planning for their review and comment; if you have any comments, please let me know. Mr. Gagnon asked Mr. Fedora for a copy of any comments he receives on the NERC white paper. Critical Infrastructure Protection Committee (CIPC) Mr. Hogue reported that CIPC plans to have a conference call on this Friday to reach consensus on the proposed three topics up for vote: 1) the Sector Specific Plan, 2) the Top Ten Vulnerabilities, and 3) the Incident Response Planning Guideline.



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There will be a noticeable amount of time at CIPC devoted to the Homeland Security Information Network (HSIN). They will be conducting tabletop exercises; at the next RCC meeting, there will be an informational update regarding this activity. At CIPC, NPCC has three voting representatives; one of those three, due to other time commitments has not been able to attend all the meetings. The Task Force on Infrastructure Security and Technology (TFIST) recommended a replacement, Mr. Jean-Guy Ouimet, Hydro-Québec TransÉnergie, who is a physical security expert. The slot in question requires physical security expertise. TFIST also recommended an alternate, Mr. Jacques Chevalier, who works for Mr. Ouimet in physical security at Hydro-Québec TransÉnergie. Mr. Gagnon asked Mr. Schwerdt to explain further why NPCC brought the comment before the NERC BOT to delay approval of the PC and OC charters. Mr. Schwerdt responded that the NPCC Board made a specific recommendation to the NERC BOT to not approve the OC Charter, as it was written, in as much as it did not include (as it was presented to the NERC BOT) the readiness evaluation piece. It was the NERC BOT‘s position, based on that comment and other comments it received from EEI, that the NERC BOT itself pulled the entire set of Charters from approval consideration. Which is a good thing, Mr. Cowbourne added, because we will get the approval, at the next NERC BOT meeting with the OC having the readiness review as part of its accountability. Mr. Gagnon replied that the action delays the membership process, since the Charters are not yet approved. Mr. Cowbourne replied that it will probably not delay things, since the NERC BOT could approve the Charters at a special conference call meeting.

Other Matters Mr. Cowbourne indicated that a status report on Pandemic Planning activities within NPCC is planned for the next RCC meeting, just so we all get a good handle on where everybody is at on that subject. The ISO’s and some of the transmission operators, maybe all of them, are well along, but we want to ensure that all NPCC members are well along. Pandemic Planning as a subset of critical infrastructure planning, and we need to be on top of it. With no other matters brought before the RCC, Mr. Cowbourne adjourned the meeting.




Date Location May 23, 2007 New York City September 6, 2007 New York City Distribution of Approved Minutes NPCC Full Member Representatives and Alternates NPCC Public Interest Representatives and Alternates Members, NPCC Inc. Board of Directors Members, NPCC CBRE Board of Directors Members, NPCC Reliability Coordinating Committee Members, NPCC Public Information Committee Members, NPCC Compliance Monitoring and Assessment Subcommittee Members, NPCC Task Force on Coordination of Operation Members, NPCC Task Force on Coordination of Planning Members, NPCC Task Force on Infrastructure Security and Technology Members, NPCC Task Force on System Protection Members, NPCC Task Force on System Studies Ms. Jennifer H. Budd Andrew J. Fawbush, Esq. Mr. Philip A. Fedora Mr. David Goulding Mr. James H. Hartwell Mr. Brian Hogue Mr. Donal J. Kidney Mr. Stanley E. Kopman Mr. H. Quoc Le Catherine P. McCarthy, Esq. Mr. John G. Mosier, Jr. Andrianne S. Payson, Esq. Mr. Reza Rizvi Mr. Frantz Roc Mr. Paul A. Roman Mr. Edward A. Schwerdt Mr. Guy V. Zito and Federal Energy Regulatory Commission



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La Régie de L’Énergie Maine Public Utilities Commission New England Conference of Public Utilities Commissioners New York State Department of Public Service Ontario Energy Board United States Department of Energy Vermont Department of Public Service

rcc minutes 20070314 - approved · 2007. 3. 14. · northeast power coordinating council...

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