Final RCC Minutes 20101130 - Northeast Power Coordinating ... · NORTHEAST POWER COORDINATING COUNCIL Reliability Coordinating Committee Minutes November 30, 2010 ... Constellation

March 15, 2011 Members, Reliability Coordinating Committee

and Members, Task Force, RSC and CC Chairs Members, NPCC Staff Re: Minutes of the November 30, 2010 Reliability Coordinating Committee meeting

Sir / Madam:

Attached find the Minutes of the November 30, 2010 meeting of the Reliability Coordinating Committee, approved at the March 3, 2011 meeting.

Sincerely,

Phil Fedora

Philip A. Fedora Assistant Vice President, Reliability Services

NORTHEAST POWER COORDINATING COUNCIL Reliability Coordinating Committee Minutes

November 30, 2010

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Mr. Gates called the meeting of the Reliability Coordinating Committee (RCC), held at The Desmond Hotel and Conference Center, Albany, New York on November 30, 2010 to order at 10:00 am.

Attendance Officers of the Reliability Coordinating Committee Donald L. Gates, Chair ISO-New England Alden Briggs, Co-Vice Chair New Brunswick System Operator Sector 1 - Transmission Owners Central Hudson Gas & Electric Corp. Thomas Duffy Central Maine Power Company Brian Conroy Consolidated Edison Company Michael Forte of New York, Inc. Hydro One Networks Inc. Paul Tremblay Hydro-Québec TransÉnergie Jean-Marie Gagnon Long Island Power Authority (proxy to Steve Marron) National Grid USA Michael Schiavone New Brunswick Power Transmission Tony O’Hara Corporation New York Power Authority Gerald LaRose – Alternate New York State Electric & Gas Corp. Raymond Kinney Northeast Utilities (via phone) Brad Bentley Nova Scotia Power Incorporated Paul Casey Rochester Gas & Electric Corporation John Allen United Illuminating Company Robert Pellegrini Vermont Transco (proxy to Kim Moulton) Sector 2 – Reliability Coordinators Hydro-Québec TransÉnergie (proxy to Jean-Marie Gagnon) IESO Kim Warren ISO-New England, Inc. Donald L. Gates New Brunswick System Operator Alden Briggs New York Independent System Operator (proxy to John Adams) Sector 3 – Transmission Dependent Utilities, Distribution Companies and Load Serving Entities Hydro-Quebec Distribution (via phone) Stephane Dufresne


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Long Island Power Authority Steve Marron - Alternate New York Power Authority (proxy to Gerald LaRose) Northeast Utilities (via phone) (proxy to Brad Bentley) Sector 4 Generation Owners Dominion Energy Marketing, Inc. Michael Garton Dynergy, Inc. (via written proxy) Entergy Nuclear Northeast (proxy to Tom Czerniewski) Long Island Power Authority (proxy to Steve Marron) New York Power Authority (proxy to Gerald LaRose) Northeast Utilities (via phone) (proxy to Brad Bentley) Ontario Power Generation, Inc. Brian Gooder Sector 5 – Marketers, Brokers, and Aggregators Constellation Energy Commodities Glen McCartney Group, Inc. HQ Energy Marketing, Inc. (proxy to Scott Leuthauser) Hydro Quebec Energy Services (US) Inc. Scott Leuthauser - Alternate Long Island Power Authority (proxy to Steve Marron) New York Power Authority (proxy to Gerald LaRose) PPL EnergyPlus LLC (via written proxy) Utility Services, LLC Brian Evans-Mongeon Sector 6 – Customers None Designated Sector 7 – State and provincial Regulatory and/or Governmental Authorities New York Power Authority (proxy to Gerald LaRose) New York State Department Edward Schrom - Alternate of Public Service Sector 8 – Sub-Regional Reliability Councils, other Regional Entities and Interested Entities New York State Reliability Council, LLC Roger Clayton NPCC Staff Jack Alvarez Senior Engineer Gerry Dunbar Senior Criteria Specialist Ben Eng Senior Compliance Engineer Philip Fedora Assistant Vice President of Reliability Services Donal Kidney Manager, System Studies


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Stanley Kopman Assistant Vice President of Compliance Registration & Enforcement Quoc Le Manager, System Planning & Protection Heidi Lewis Financial Analyst Margaret Mayora (via phone) Compliance Attorney John Mosier, Jr. Assistant Vice President of System Operations Lee Pedowicz Manager, Reliability Standards Frantz Roc Manager, Information Technologies Paul Roman Manager, Operations Planning Edward A. Schwerdt President & Chief Executive Officer Guy Zito Assistant Vice President, Standards Guests Pete Brandien ISO-New England Richard Burke ISO-New England Jim Castle Chair, Task Force on Coordination of

Operation Dave Conroy Chair, Task Force on System Studies Dave Daley New Brunswick System Operator Ron Falsetti AESI Martin Ferland Chair, Task Force on Infrastructure Security

&Technology Jeffery Fenn SGC (on behalf of Bangor Hydro Electric) Greg Goodrich New York ISO Bryan Gwyn Chair, Task Force on System Protection David Kiguel Hydro One Networks Michael Lombardi Northeast Utilities Brent Oberlin (via phone) ISO-New England Michael Parisi New York Power Authority Isen Widjaja (via phone) Chair, SS-38 Working Group

Quorum Statement Mr. Fedora indicated that a quorum has been achieved, by member attendance, proxy or alternate designation.

Antitrust Guidelines for NPCC Meetings Mr. Fedora reviewed the NPCC Antitrust Guidelines in the Agenda package, and suggested contacting NPCC Inc.’s Assistant Secretary, Andrianne S. Payson at (212) 424-8218 for further information.


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President & CEO Report

Mr. Schwerdt reported that on November 18, 2010, FERC issued its long awaited Order on Revision of the Electric Reliability Organization Definition of Bulk Electric System (BES). The Order, included in the RCC agenda package, directs the ERO, through its Reliability Standards Development Process, to revise the existing BES definition to address the Commission’s technical concerns regarding current inconsistencies and ambiguities, and to ensure that the definition, and these are the key phrases, encompasses all facilities necessary for operating an interconnected electric transmission network. The Commission believes that the best way to accomplish this is to eliminate the unilateral Regional discretion in the current definition, maintain a bright-line threshold that includes all facilities operated at or above 100 kV except defined radial facilities, and establish an exemption process and criteria for excluding facilities that the ERO would determine are not necessary for operating the interconnected transmission network. In addition, the Order allows the ERO to develop an alternative proposal for addressing FERC’s concerns with the present definition with the understanding that such alternative must include a technical record sufficient enough for the Commission to make an informed decision, must be at least as effective as, or more effective than, the Commission’s proposed approach in addressing the identified technical and other concerns, and also may not result in a reduction in reliability. The Order directs the ERO to submit its modifications to the BES definition no later than one year from the effective date - that is, no later than January 25, 2012 - with an expectation of transition periods to implement the definition not to exceed 18 months from the time the Commission approves a revised definition and exemption process. Any exemption requests and implementation plans have to also be filed along with the definition on the January 25, 2012 date. Finally, the Commission acknowledges its international jurisdictional limitations and encourages consistent treatment of transmission lines that cross the U.S. border. At the September meeting, the NPCC President’s report to the RCC noted that it would be both prudent and essential for NPCC members to be taking proactive steps to bring their 100 kV and above facilities into compliance with NERC standards. In addition, the Task Force on System Studies was advised to begin framing out the outline of an exemption process. Both of those recommendations are repeated here today.


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In addition, NPCC staff has been working for some time now with representatives from other Regional Entities, specifically WECC, FRCC and RFC, on the development of a Standards Authorization Request, or SAR, for the development of a revised BES definition. With the BES Order now in place, this activity has been joined by NERC and the remaining Regional Entities and discussions are ongoing regarding what would constitute an appropriate exemption criteria and process. It is likely that the SAR will be submitted shortly and work on the standard will begin. Mr. Fedora has been designated to lead this effort for NPCC. Lastly, as a brief summary of the November NERC Member Representatives Committee and Board of Trustees meetings, the MRC discussed the need for better prioritize in the development of standards, and the identification of key reliability challenges to be considered at a FERC conference to be held in early 2011. The NERC Board authorized an appeal of a September 16th FERC Order involving the process for responding to a Reliability Standard directive, approved the Standards Oversight and Technology Committee charter, approved a number of Reliability Standards, specifically including NPCC’s Disturbance Monitoring Regional Standard, approved the Critical Infrastructure Strategic roadmap and the Critical Infrastructure Strategic Initiatives Coordinated Action Plan, and endorsed the development of clarifications to the October 7th Facilities Ratings Alert. A second webinar on that Facilities Ratings Alert was conducted yesterday, with revised expectations and extended timelines identified. Discussion of this topic has been added to the RCC Agenda. In response to a question by Mr. Gagnon regarding the forum envisioned for discussion of BES cross border issues, Mr. Schwerdt replied that NERC has scheduled discussion of the BES Order on all its standing committee meetings next week. He indicated that as of right now, no specific forum has been identified, and encouraged Canadian representation/participation on the SAR Drafting Team. Mr. Schwerdt stated as the NERC process develops, NPCC can entertain discussion of Canadian issues raised at the RCC, mindful that NPCC is just one of three cross border regional entities in NERC.

Chair Report Meeting Agenda Mr. Gates indicated the following changes to the Agenda; the endorsement to post the UFLS Regional Standard for pre-ballot review has been removed from the consent agenda, and will be discussed separately under the items for approval; the ERAG update provided in the materials for approval of the 2010 – 2011 NPCC Reliability Assessment


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will be provided following the status reports; the approval of the proposed RCC 2011 -2012 Work Plan will follow the RCC consideration of the proposed 2011 – 2012 Task Force Work Plans, and an update regarding the NERC Facilities Ratings Alert will be provided along with the other NERC Highlights. The RCC approved the Agenda, as modified. 2011 Meeting Dates Mr. Gates indicated that the March 2nd date for the RCC may change to March 3rd; the following dates were proposed for 2011 RCC meetings in the Agenda package: Wednesday, March 2nd - Con Ed, New York City Wednesday, June 1st - Con Ed, New York City Thursday September 8th - Con Ed, New York City Tuesday, November 29th - Marriott Bloor Yorkville (Toronto, Ontario)

subject to confirmation of room availability by Con Ed. [note: subsequently, the March RCC meeting was changed to Thursday, March 3rd; Con Ed has confirmed the RCC meeting dates.] FERC BES Order Mr. Fedora added that in September, WECC, NPCC and FRCC began informally discussing their respective Regional BES efforts. There was a common desire to try to coordinate efforts, along with NERC, prior to FERC action on the BES Notice of Proposed Rulemaking. While it is recognized that the Regions all have different methodologies to technically assess whether an element should or should not be included in the BES, it was thought to be beneficial to see whether a common approach (in terms of BES definition and exclusion process) could be identified, to provide a starting point for coordinated Regional discussions going forward. The initial results of the WECC/NPCC/FRCC coordination group was summarized in the October 21, 2010 letter to the ERO - REMG provided in the Agenda package - a common BES framework and principles were proposed for consideration, along with an Action Plan. Representatives from the other Regional Entities and NERC staff were invited and have participated in this effort. The resultant Regional BES System Definition Coordination Group ‘Concept Document’ provided in the Agenda package will be sent to the NERC Standing Committees for their discussion and comments at next week’s meetings.


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Mr. Fedora also mentioned that FERC staff is scheduled to discuss the BES Order at this afternoon’s NPCC Governmental/Regulatory Affairs Advisory Group meeting, following the RCC meeting. Mr. Gooder asked about the make-up of the Regional BES Coordination Group; Mr. Fedora responded that initial participation was by NPCC, WECC and FRCC representatives; later RFC also began to participate; however, all Regions were invited to participate. Mr. Schwerdt added that the NERC response to the NOPR was to affect any changes to the BES Definition through the NERC Standard process; FERC endorsed that approach in the Order. A Standard Drafting Team will be formed, following an expedited open, stakeholder process; but the composition of the Drafting Team hasn’t been decided at this time. Mr. Duffy stated that it doesn’t seem achievable to have BES implementation plan proposed-at the same time the definition is filed. Mr. Schwerdt responded that that’s the way FERC has laid it out in the Order. In response to a question regarding if NPCC would pursue a performance based BES definition, Mr. Schwerdt responded that if the question meant is NPCC going to continue its A-10 methodology for its BES Definition – that was commented/reviewed/critiqued by FERC in the Order. He said that position is something of a non-starter. NPCC is not unilaterally going to take a position that it would not likely win. A stronger approach would be to develop an intelligent exception process that was not discredited in the Order (similar to the FERC seven factor test). FERC identified BES elements as those facilitates necessary to operate the system in the Order– for example, if a 100 kV or higher line is part of a flow gate – it’s BES, if it provides service to a nuclear unit, – it’s BES. He said there is a lot of instruction within the Order, laced with FERC’s concerns. He said the strategy is to work with what FERC has already recognized and approved and move forward from there. Mr. Kiguel asked when the SAR is expected to be submitted for consideration by the NERC Standards Committee (SC). The SC has to accept the SAR, then ask for and approve nominations for the SAR Drafting Team. Mr. Fedora responded that there is no answer to this question at this time. NERC is still in the process of evaluating their next steps.


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Mr. Duffy asked if NPCC would be considering a challenge of this Order based on FERC over stepping there statutory authority in this Order. Mr. Schwerdt responded that the FPA broadly defines the Bulk Power System; FERC, in this order, chose not to take on some of those jurisdictional arguments – FERC limited their discussion to a subset of that what they defined as the Bulk Electric System, and they parsed out the differences between the two, so that a request for rehearing could not be mounted based on jurisdictional issues. It would not be NPCC intent to take on jurisdictional issues that are not within our scope or mandate, but to utilize the ability of the industry itself to self determine what should or should not be included in the BES Definition. It is clear that 100kV and above is included, unless it is specifically excluded. That’s why NPCC’s focus will be on a rational and repeatable exception approach that is applied uniformly across the United States, and potentially, across all of North America. Mr. Duffy then asked if any type of risk based, performance based methodology would be acceptable. Mr. Schwerdt responded that FERC also raised the bar for any kind of proposed specific regional methodology – for instance a TDF approach – would need to either be at least as stringent as a North American approach, or address specific facilities differences. There is room for regional methodologies – but no longer unilateral regional authority to determine approaches. The A-10 methodology would be maintained for NPCC’s more stringent regional criteria. Critical Energy Infrastructure (CEII) Information Non Disclosure Agreement (NDA) Mr. Gates referred to the CEII NDA included in the Agenda package allows for an executive of the company to sign for their employees. Mr. Fedora explained that NPCC has two separate CEII NDAs; one for NPCC Members, one for non-Members. For the Member CEII NDA, an executive officer of the Member organization can sign on behalf of the organization’s employees. In doing so, said officer assumes the responsibility of tracking employees accessing CEII, safeguarding of CEII information and other related responsibilities set forth in the NDA. The non-Member NDA must be signed by the individual employee or consultant seeking CEII access.


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Mr. Gates asked the RCC to consider whether or not technical details considered CEII should be presented at RCC meetings, or if high level summaries of the analysis prepared by the Task Forces having access to that information is sufficient. He asked the RCC to be prepared to discuss their preference at the March meeting. Mr. Warren thanked NPCC staff for listening to the IESO concerns during the development of the corporate CEII NDA, and asked if NPCC was entertaining comments on this revised agreement, or if it should be considered as finalized. Ms. Mayora responded that her recommendation is to consider it as final, given that the previous comments and concerns were addressed. Mr. Warren said his legal counsel hasn’t had a chance to review the document. He indicated the intent was to have one agreement that could be used for all company personnel involved in NPCC related activities; he said he would promptly bring to NPCC’s attention any major concerns that may come from their legal review of the CEII NDA. Mr. Schwerdt said that the level of detail speaks to the heart of what is expected of the RCC, as NPCC’s top technical committee; not only regarding the thoroughness of the RCC’s review, but also in the policy implications associated with the technical details that the Task Forces bring to it. He believed it would be hard for the RCC to thoroughly do its job on behalf of the NPCC Board if it did not have full access to all of the related technical details, especially as it reviews the policy implications. Mr. Fedora added there are other ways to provide for RCC review of specific CEII marked materials, but they are administratively burdensome to administer with a group the size of the RCC. Mr. Gates again asked RCC members to be prepared to discuss the issue at the next meeting. Nominating Committee Mr. Gates stated that Mr. Walters had a reassignment in his company, and as a result had to step down from his RCC responsibilities. He asked for three volunteers to form a Nominating Committee that would recommend a candidate (or candidates) for the position of a 2011 Co-Vice Chair for RCC selection at the next meeting. Messrs. Warren, Evans-Mongeon, and Gagnon volunteered. Mr. Evans-Mongeon agreed to act a Nominating Committee Chair.


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Mr. Gates encouraged RCC members to consider the position, and if they had any questions to contact Mr. Evans-Mongeon or the Nominating Committee. Mr. Fedora agreed to help coordinate the Nominating Committee’s activities. Mr. Fedora added that according to the Amended and Restated Bylaws of Northeast Power Coordinating Council, Inc. “... the [Committee] Co-Vice Chair designees shall be from different voting Sectors …” Mr. Gates stated that the commitment normally involves six years, two 2-year terms as Co-Vice Chair and then one 2-year term as Chair; however, obviously plans change, as witnessed; he stated it’s a worthy position and encouraged the RCC members to consider the assignment. 2011-2012 RCC Work Plan Mr. Gates again indicated that the proposed 2011-2012 RCC Work Plan has been provided in the Agenda package, and will be considered following RCC consideration of the respective 2011 – 2012 Task force Work Plans.

Consent Agenda The Reliability Coordinating Committee approved the following Consent Agenda items: September 9, 2010 Meeting Minutes The Draft-For-Approval Minutes of the September 9, 2010 Reliability Coordinating Committee, as included in the Agenda package, with minor changes noted. Roster Changes The following changes to Task Force memberships: Task Force on System Protection Mr. Anthony Napikoski as United Illuminating Company primary representative. Mr. Alex L. Echeverria as New York Power Authority primary representative,

succeeding Mr. Fred Pagano. Task Force on Infrastructure Security and Technology Mr. Derek Hughes, as Hydro One Networks, Inc. primary representative. Mr. Greg Dodson as Dominion primary representative, succeeding Mr. Dennis Sollars. Ms. Summer Esquerre as NextEra Energy, Inc. primary representative. Mr. David Rivera as New York Power Authority primary representative, succeeding

Mr. Al Martin. Mr. Neal Hickey as New Brunswick System Operator primary representative.


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Mr. Daniel Yagudayev as Consolidated Edison Company of New York, Inc. primary representative, succeeding Mr. Michael Selbach.

Task Force on System Studies Brian Evans-Mongeon as Utility Services primary representative.

Working Group on Review of NPCC Basic Criteria (CP-11) Mr. Dan Schwarting as ISO-New England, Inc. alternate representative.

Working Group on Physical Security (IST-5) Mr. Benoit Tardif as Hydro-Quebec primary representative.

Working Group on System Operator Training (CO-02) Mr. Nicolas Ingman as Independent Electric System Operator alternate representative.

Working Group Operational Review, Coordination and Assessment (CO-7) Mr. Allan McNaughton of New Brunswick System Operator, succeeds Mr. Martin

Boisvert of Hydro-Quebec, as Chairman. Mr. Michael Knowland of ISO New England, Inc. as Vice Chair.

Working Group on NPCC System Operations Managers (CO-08) Mr. John Norden as ISO New England Inc. alternate representative, succeeding

Mr. Michael N. Taniwha Mr. David A. Daley as New Brunswick System Operator alternate representative,

succeeding Mr. Ross Stairs. Mr. Guy Quintin as Hydro-Québec TransÉnergie alternate representative, succeeding

Mr. Gratien Charette.

Working Group on System Operational Tools (CO-10) Mr. Jacques Audet of Hydro-Quebec, succeeds Mr. Dean Landers of New Brunswick

System Operator as Chairman. Ms. Laura McLeod as New Brunswick System Operator primary representative,

succeeding Mr. Dean Landers. Mr. De Dinh Tran of New York Independent System Operator as Vice Chair.

Working Group on NPCC Restoration (CO-11) Mr. Edward Rappold as ISO New England Inc. primary representative, succeeding

Mr. Osman M. Bileya. Messrs. Paul Maurice and Mathieu Peloquin as Hydro-Québec TransÉnergie alternate

representatives.


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2010 A-10 BPS List Approved as provided in the Agenda package. Regional Reserve Sharing Standard Assignment to the TFCO Approved as provided in the Agenda package. The following Interim reviews of Resource Adequacy provided in the Agenda package: New England Ontario Quebec New York

The following Interim Transmission Reviews provided in the Agenda package: Quebec Maritimes

Relay Mis-Operations Working Group & Scope Approved as provided in the Agenda package.

Reliability Coordinating Committee Actions Endorsement to Post UFLS Regional Standard for Pre-Ballot Review Mr. Zito summarized the materials provided in the Agenda package. The Task Force on System Studies (TFSS) was assigned the responsibility of developing Regional Standard PRC-006-NPCC-1 Automatic Underfrequency Load Shedding by the Reliability Coordinating Committee on September 4, 2008. The standard was developed in response to a request from NERC to satisfy FERC Order 693 issued in 2006. At that time, twenty four standards were identified as "fill in the blank" and as a result the FERC directed NERC to modify the individual standards reliance on the Regional Reliability Organization. Additionally, of those twenty four standards, four were identified by NERC and the regions to be regionally specific enough to warrant the development of a regional standard and Under Frequency Load Shedding was one of those four standards. The UFLS Regional Standard Drafting Team (RSDT) was formed by the TFSS and along with NPCC staff and other industry participants has developed this draft standard at open and inclusive meetings made public through the NPCC website.


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The standard was posted twice for industry comment and the UFLS RSDT either incorporated comments received through revisions to the document, or explanations to commenters were provided regarding the disposition of their concerns. Finally, individual commenters have been notified that responses to all comments have been posted on the NPCC website. These materials have been included in the Agenda package. He noted that the effective date of the implementation plan, January 1, 2016 is the same end date that resides with the Directory project. The requirements, R1 through R8, those will be completed by January 1, 2016 – that’s when the standard would be for used for compliance. He added that the Continent wide NERC UFLS Standard was approved by the NERC Board on November 4, 2010. He stressed the importance of moving the NPCC UFLS standard forward in order to demonstrate a way of implementing the goals of the Continent wide UFLS Standard. In addition, NPCC Staff and the RSDT Chair met at the FERC to discuss their issues and concerns, and NERC Staff recently participated with NPCC Staff and Legal to perform a “Quality Review” of the standard. The version being transmitted to the RCC reflects the improvements based on these discussions. He said it’s also very important that the standard reflect the technical assumptions used in the supporting studies; the standard can’t change the underlying technical justification for the requirements. The document has been finalized and in accordance with the FERC filed and approved NPCC Regional Reliability Standards Development Procedure; the TFSS is seeking RCC endorsement for the standard to be transmitted to the Regional Standards Committee. The RSC will then consider it for approval to post for a thirty day preballot review and subsequent ballot of the NPCC General Members and approval by the NPCC Board of Directors. Mr. Gagnon stated while Hydro-Quebec is not opposed to endorsing pre-ballot of the standard, it must be clear that the compliance obligation of the standard rests with the Transmission Owner (TO) –ultimately, the TOs must meet the requirement. Sooner than later, the TOs should be informed of what they need to do. Mr. Zito stated that NPCC has tried, at the compliance workshop and classroom sessions, to get the message out to the individual TOs.


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In response to a question by Mr. Briggs, Mr. Zito responded that once the standard has regulatory approval in the US and the provinces, the directory could be retired. In response to a question by Mr. Pellegrini about compliance during the implementation phase, Mr. Zito explained the difference between compliance to the Directory requirements (which falls under the Criteria Compliance Criteria Program (non-monetary)) and mandatory compliance to the Regional and Continent wide standards. The RCC endorsed posting the UFLS Regional Standard for Pre-Ballot Review (one abstention). NPCC Long Range Adequacy Overview Mr. Fedora gave the presentation of the NPCC Long Range Adequacy Overview (LRAO) provided in the Agenda package. He explained that the objective of the study was to evaluate the near term seasonal and long-range (five year) adequacy of NPCC Areas’ and reflecting neighboring regional plans proposed to meet their respective resource adequacy planning criteria through a multi-area probabilistic assessment. In addition to estimating the annual NPCC Loss of Load Expectation for the study period, the LRAO also proved an estimate of the annual NPCC Loss of Load Hours and Expected Unserved Energy, probabilistic metrics recommended by the NERC Generation & Transmission Reliability Planning Models Task Force for a regional trial assessment coordinated by the NERC Resource Issues Subcommittee for 2011. Mr. Briggs added that the Task Force on Coordination of Planning discussed and approved the LRAO at their November 9, 2010 meeting. The RCC approved the NPCC Long Range Adequacy Overview as presented in the Agenda Package. SS-38 Working Group Recommendation for Generator Underfrequency tripping Threshold Mr. Widjaja, Chair of the SS-38 Working Group summarized the background for the additional Underfrequency Load Shedding (UFLS) analysis provided in the Agenda package. He explained that at the September 9, 2010 meeting, the RCC approved the SS-38 additional analysis report on the Underfrequency Load Shedding Study and requested that SS-38 Working Group follow up with a recommendation for the MW threshold for generator under-frequency tripping requirement that could be considered in the development of the UFLS Standard.


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Based on the analysis and the proposed method for assessing potential thresholds in the attached report, the SS-38 Working Group recommends the following thresholds for applicability of under-frequency trip settings for generators connected to the NPCC system at all voltage levels: Individual generating units ≥ 1 MW (gross nameplate rating) Generating plant/facility ≥ 1 MW (gross aggregate nameplate rating)

He stated that it was also the understanding of the SS-38 Working Group that the recommended threshold for generator applicability be uniform for the entire NPCC region. The RCC approved the SS-38 Work Group’s Recommendation for Generator Underfrequency tripping Threshold provided in the Agenda package. 2010 – 2011 NPCC Winter Reliability Assessment Mr. Roman summarized the work of the NPCC CO‐12 Operations Planning Working Group regarding the assessment of reliability within NPCC for the 2010‐11 Winter Operating Period. Portions of the report summarizing the 2010-11 Winter multi‐area probabilistic reliability assessment by the CP‐8 Working Group was previously approved by the RCC. Results of that assessment are included as a chapter in this report. He summarized those aspects that the CO‐12 Working Group has examined to determine the reliability and adequacy of NPCC for the winter of 2010‐11. The report evaluates NPCC’s and the associated Balancing Authority areas’ ability to deal with the differing resource and transmission configurations within NPCC and the associated Balancing Authority areas’ preparations to deal with the possible identified uncertainties. The RCC approved the 2010 – 2011 NPCC Winter Reliability Assessment as provided in the Agenda package. Keene Road Type I SPS Modifications Mr. Fenn, of SGC Engineering, LLC, representing Bangor Hydro provided a presentation of the proposed modifications to the Keene road Type I Special Protection System, as provided in the Agenda package. Messrs Castle and Briggs affirmed that the TFCO and TFCP recommend RCC approval the modifications of the referenced special protection systems, as presented.


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The RCC approved the modifications to the Keene Road type I SPS as provided in the Agenda package. Endorsement of the NPCC Criteria Compliance and Enforcement Program and Retirement of NPCC Document A-8 Mr. Kopman summarized the materials provided in the Agenda package. He explained that the NPCC Compliance Program consists of two parts: the NERC Compliance Monitoring and Enforcement Program (CMEP), which monitors, assesses and enforces registered entities’ compliance to NERC and Regional Reliability Standards and the NPCC Reliability Compliance and Enforcement Program (RCEP), which monitors, assesses and enforces NPCC Membership’s compliance to identified more stringent and/or specific NPCC Criteria as contained in NPCC Directories. For over the last year the NPCC Compliance Committee has been developing a replacement program for the current RCEP to address the changes that have occurred in NERC Reliability Standards and NPCC Directories. At its November 17, 2010 conference call meeting, the NPCC Compliance Committee finalized and approved the two documents provided in the Agenda package; CCEP-1, The NPCC Criteria Compliance and Enforcement Program (CCEP) Process Document, and CCEP-2, the Implementation Plan for 2011 NPCC Criteria Compliance Program. These documents explain the CCEP process and how the program will be implemented in the year 2011. As the overall process document, CCEP-1 was posted in the NPCC Open Process for membership comment. Comments received during that posting plus additional comments received from Compliance Committee members were reviewed and the resulting document was developed. As part of its charter the NPCC Compliance Committee developed and approved the Implementation Plan for the 2011 CCEP. With the introduction of the CCEP and the CCEP-1 and CCEP-2 documents and the need to seek Membership approval for the retirement of an “A” or Criteria Document, the NPCC Compliance Committee is requesting that the Reliability Coordinating Committee approve the action to distribute to the NPCC Membership a request that NPCC Criteria Document A-8, NPCC Reliability Compliance and Enforcement Program, be retired along with its associated documents, NPCC Guideline B-22, Guidelines for Implementation of the NPCC Inc. Compliance Program and NPCC Procedure C-32, Review Process for NPCC Reliability Compliance Enforcement Program. The RCC endorsed the NPCC Criteria Compliance and Enforcement Program as presented in the Agenda package and approved recommending that the NPCC Full


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Membership retire NPCC Criteria Document A-8, NPCC Reliability Compliance and Enforcement Program, along with its associated documents, NPCC Guideline B-22, Guidelines for Implementation of the NPCC Inc. Compliance Program and NPCC Procedure C-32 (one opposed). 2011 -2012 Task Force Work Plans Mr. Gates referred the RCC to the materials provided in the Agenda package. The RCC approved 2011-2012 Task Force Work plans provided in the Agenda package. 2011 -2012 RCC Work Plan The RCC then approved the 2011-2012 RCC Work plan provided in the Agenda package.

NERC Highlights and Agenda Items Operating Committee (OC) Mr. Mosier reviewed the following topics on the December 2010 OC Agenda: Status of the NERC Events Analysis trial period and process, in response to a question,

Mr. Mosier explained that this process applies to the system as a whole, not selected systems.

Approval of the NERC Severe Impact Resilience (SIR) Task Force: in response to a question, Mr. Mosier indicated that NPCC staff would be participating in the Task Force

Time Monitor Field Trial. Definition of the Bulk Electric System (BES) definition Reliability Metrics Working Group

Planning Committee (PC) Mr. Fedora added that in addition to the approval of the SIR Task Force, and discussion of the BES Definition and Reliability Metrics Working Group scope change mentioned in the OC review, the PC would also be considering the following items at the December 2010 PC meeting: Process for the review of PC Reports Generation &Transmission Reliability Planning Models Task Force revised Metrics and

Methodology document and Trial period of metrics proposed to be conducted by the NERC Resource Issues Subcommittee

Consideration of several White Papers, including: o Potential Reliability Impacts of Emerging Flexible Resources


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o Methods to Model and Calculate Capacity Contributions of Variable Generation for Resource Adequacy Planning

o Power System Model Validation o Reliability Fundamentals of System Protection

Critical Infrastructure Protection Committee (CIPC) Mr. Martin provided an overview of the following items on the December 2010 CIPC Agenda: Cyber Attack Task Force Scope SIR Task Force DHS Control System Program Team CYMRU Presentation Technical Feasibility Exception process Classified Aurora briefing CIP Standard - version 4

NERC Facilities Rating Alert Mr. Mosier explained that NERC provided an update to its October 7, 2010 Recommendation to Industry entitled “Consideration of Actual Field Conditions in Determination of Facility Ratings.” Transmission Owners and Generator Owners of bulk electric system facilities need to review their current facility ratings methodology for their transmission lines to verify the methodology used is based on actual field conditions and determine if their ratings methodology will produce appropriate ratings when considering differences between design and field conditions. If entities have not previously verified that the facility design, installation, and field conditions are within design tolerances when the facilities are loaded at their ratings, then entities are required by January 18, 2011, to describe its plans to complete such an assessment of all its transmission lines, with the highest priority lines assessed by December 31, 2011, medium priority lines by December 31, 2012, and the lowest priority by December 31, 2013. At the conclusion of each year, each Transmission Owner and Generator Owner must report to its Regional Entity a summary of the assessments and identification of all transmission facilities where as-built conditions are different from design conditions, resulting in incorrect ratings, and their associated mitigation timelines. Remediation is expected within one year from identification of the issue or on a schedule approved by the Regional Entity if longer than a year. Owners are also expected to coordinate with their respective operating and planning organizations to coordinate interim mitigation strategies.


November 30, 2010


Status Reports Mr. Gates referred the RCC to the materials provided in the Agenda package, and entertained discussion on the following: Directory No. 5 Follow-up Mr. Castle provided an overview of the Task Force on Coordination of Operation (TFCO) activities provided in the Agenda package regarding the identified issues regarding Directory No. 5 which required further deliberation and resolution. These included the treatment of unit contingent sales, wheeling in carrying out a SAR request, the proper level of synchronized reserve and the development of an interim reserve sharing directory to bridge the gap between the legacy NPCC Document C-38, "Procedure for Operating Reserve Assistance," and the drafting of a Regional Standard on reserve sharing. Mr. Briggs asked if any reliability analysis would support lowering the current levels of synchronized operating reserve. Mr., Castle responded that the TFCO had reviewed the issue and couldn’t find a reliability reason to support lowering the reserve level. NPCC Tie Benefits Analysis Update Mr. Fedora reviewed the preliminary results for the year 2011 presented in the Agenda package. He explained that the NPCC Tie Benefits Analysis has been updated for the year 2011 using the previously approved methodology. Following the Task Force of Coordination of Planning’s review of the results for 2011 and 2015 and corresponding report, RCC approval will be sought in December 2010. Cross-Border Emergency Telecommunications Report Mr. Martin reviewed, the status report provided in the Agenda package. He explained that since the 2009 status report, the IST-2 Working Group conducted three tests of the Cross Border Emergency Telecommunications system; the CO-8 working Group conducted two tests. The IST-2 Working Group and the CO-8 Working Group agreed that starting in November 2010, the CO-8 Working Group will conduct these tests monthly; this also serves as system operator training. In summary, the tests show that Iridium satellite communications to/from ISO-NE, NYISO, IESO, NBSO and TransEnergie range from Good to Acceptable.


November 30, 2010

21

NERC Protection Coordination Reference Paper Mr. Gwyn explained that the Task Force on System Protection (TFSP) recently completed their review of the NERC Reference Document on Power Plant and Transmission System Protection Coordination. The TFSP review included an estimate of the resource impact if coordination will be implemented as recommended in the Document. He indicated that the TFSP supports this Technical Reference Document and recommends that Members utilize it in their coordination studies. Eastern Interconnection Reliability Assessment Group (ERAG) Update Mr. Roman gave the presentation of the Eastern Interconnection Reliability Assessment Group (ERAG) Seasonal Assessments provided in the Agenda package. He indicated that ERAG has sent a survey to the six Regions in the Eastern Interconnection asking for feedback regarding: 1) the studies and the study results; 2) how are they used; 3) are there suggestions for improvement; and, 4) are there suggestions for any other new items that could be studied that would be useful within NPCC.

Informational Items Mr. Gates referred the RCC to the informational items included in the Agenda package.

Other Matters Having no other items to consider, the RCC meeting was then adjourned. Next RCC Meeting Date

Location

Changed to March 3, 2011 Consolidated Edison, New York City

Distribution of Approved Minutes NPCC Full & General Member Representatives and Alternates Members, NPCC Board of Directors Members, NPCC Reliability Coordinating Committee Members, NPCC Public Information Committee Members, NPCC Compliance Committee Members, NPCC Regional Standards Committee 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


November 30, 2010


NPCC Officers NPCC Staff Andrew J. Fawbush, Esq. Catherine P. McCarthy, Esq. Andrianne S. Payson, Esq. and Federal Energy Regulatory Commission – Joseph McClelland La Régie de L’Énergie – Caroline Dupuis Ontario Energy Board – Peter Fraser United States Department of Energy – David Meyer New Brunswick Department of Energy – Stephen Waycott Nova Scotia Utility & Review Board – S. Bruce Outhouse, Q.C.

Final RCC Minutes 20101130 - Northeast Power Coordinating ... · NORTHEAST POWER COORDINATING COUNCIL Reliability Coordinating Committee Minutes November 30, 2010 ... Constellation

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