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Agenda Member Representatives Committee August 15, 2012 | 1:00-5:00 p.m. Eastern Hilton Quebec 1100, Rene-Levesque Blvd East Quebec, QC Canada G1R 4P3 418-647-6500 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice Consent Agenda

1. Minutes* ― Approve

a. July 10, 2012 Conference Call

b. May 8, 2012 Meeting

2. Future Meetings*

3. Elections and Nominations*

a. Member Representatives Committee (MRC) Officer and Sector Elections

b. Update from the Board of Trustees Nominating Committee

4. Remarks from Gerry Cauley, NERC President and CEO

5. ERO Business Plan and Budget Process*

6. Standards Process Input Group (SPIG) Recommendations*

a. Reliability Issues Steering Committee (RISC) Charter and Initial Slate to the RISC (Recommendation 2)

b. Status of Other Recommendations

i. Standards Committee Report (Recommendations 1, 4, and 5)

ii. Management Report (Recommendation 3)

7. Status and Policy Input for Standards Projects*

a. Bulk Electric System (BES) Definition – Phase 2 Report

b. Adequate Level of Reliability Task Force (ALRTF) Status Report

c. Status of Communications Standards

Member Representatives Committee Agenda August 15, 2012

2

8. Additional Discussion of MRC Informational Session Items, August 8*

a. Entity Impact Evaluation Template

b. Compliance Enforcement Initiative

c. Find, Fix, Track and Report (FFT) Order Paragraph 81- Lower Level Facilitating Requirements

d. NERC Compliance Process Bulletin #2012-001: Applicability of PRC-023 for Generators

9. Report on Rules of Procedure Process Improvements*

10. Follow-up Activities from the 2011 Southwest Outage*

11. Regulatory Update*

*Background materials included.

Antitrust Compliance Guidelines I. General It is NERC’s policy and practice to obey the antitrust laws and to avoid all conduct that unreasonably restrains competition. This policy requires the avoidance of any conduct that violates, or that might appear to violate, the antitrust laws. Among other things, the antitrust laws forbid any agreement between or among competitors regarding prices, availability of service, product design, terms of sale, division of markets, allocation of customers or any other activity that unreasonably restrains competition. It is the responsibility of every NERC participant and employee who may in any way affect NERC’s compliance with the antitrust laws to carry out this commitment. Antitrust laws are complex and subject to court interpretation that can vary over time and from one court to another. The purpose of these guidelines is to alert NERC participants and employees to potential antitrust problems and to set forth policies to be followed with respect to activities that may involve antitrust considerations. In some instances, the NERC policy contained in these guidelines is stricter than the applicable antitrust laws. Any NERC participant or employee who is uncertain about the legal ramifications of a particular course of conduct or who has doubts or concerns about whether NERC’s antitrust compliance policy is implicated in any situation should consult NERC’s General Counsel immediately. II. Prohibited Activities Participants in NERC activities (including those of its committees and subgroups) should refrain from the following when acting in their capacity as participants in NERC activities (e.g., at NERC meetings, conference calls and in informal discussions):

• Discussions involving pricing information, especially margin (profit) and internal cost information and participants’ expectations as to their future prices or internal costs.

• Discussions of a participant’s marketing strategies.

• Discussions regarding how customers and geographical areas are to be divided among competitors.

• Discussions concerning the exclusion of competitors from markets.

• Discussions concerning boycotting or group refusals to deal with competitors, vendors or suppliers.

NERC Antitrust Compliance Guidelines 2

• Any other matters that do not clearly fall within these guidelines should be reviewed with NERC’s General Counsel before being discussed.

III. Activities That Are Permitted From time to time decisions or actions of NERC (including those of its committees and subgroups) may have a negative impact on particular entities and thus in that sense adversely impact competition. Decisions and actions by NERC (including its committees and subgroups) should only be undertaken for the purpose of promoting and maintaining the reliability and adequacy of the bulk power system. If you do not have a legitimate purpose consistent with this objective for discussing a matter, please refrain from discussing the matter during NERC meetings and in other NERC-related communications. You should also ensure that NERC procedures, including those set forth in NERC’s Certificate of Incorporation, Bylaws, and Rules of Procedure are followed in conducting NERC business. In addition, all discussions in NERC meetings and other NERC-related communications should be within the scope of the mandate for or assignment to the particular NERC committee or subgroup, as well as within the scope of the published agenda for the meeting. No decisions should be made nor any actions taken in NERC activities for the purpose of giving an industry participant or group of participants a competitive advantage over other participants. In particular, decisions with respect to setting, revising, or assessing compliance with NERC reliability standards should not be influenced by anti-competitive motivations. Subject to the foregoing restrictions, participants in NERC activities may discuss:

• Reliability matters relating to the bulk power system, including operation and planning matters such as establishing or revising reliability standards, special operating procedures, operating transfer capabilities, and plans for new facilities.

• Matters relating to the impact of reliability standards for the bulk power system on electricity markets, and the impact of electricity market operations on the reliability of the bulk power system.

• Proposed filings or other communications with state or federal regulatory authorities or other governmental entities.

Matters relating to the internal governance, management and operation of NERC, such as nominations for vacant committee positions, budgeting and assessments, and employment matters; and procedural matters such as planning and scheduling meetings.

Draft Minutes Member Representatives Committee Pre-Meeting Conference Call July 10, 2012 | 11:00 a.m. Eastern Chair Scott Helyer convened a duly‐noticed open meeting by conference call of the North American Electric Reliability Corporation’s Member Representatives Committee (MRC) on July 10, 2012 at 11:00 a.m. Eastern. The meeting announcement, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. MRC membership attendance/roll call was not necessary since no quorum was required. NERC Antitrust Compliance Guidelines and Public Meeting Notice Holly Mann, committee secretary, directed the participants’ attention to the NERC Antitrust Compliance Guidelines and the public meeting notice. Review of Draft MRC Agendas: August 8 and 15, 2012 Chair Helyer reviewed the preliminary agendas for the upcoming August 8 MRC Informational Session and the August 15 meeting in Quebec City, Canada (Exhibits D and E, respectively). Topics for discussion during these meetings include: August 8 – updates on the 2012 Long‐term Reliability Assessment (LTRA) and emerging issues, risk‐based compliance monitoring and entity assessments, Compliance Enforcement Initiatives and Paragraph 81, NERC bulletin #2012‐001: PRC‐023‐1, and the progress towards the recommendations of the Standards Process Input Group (SPIG). August 15 – updates on MRC nominations, ERO Business Plan and Budget (BP&B) process, Bulk Electric System (BES) and Adequate Level of Reliability (ALR) definitions, communications standards, Rules of Procedure, follow‐up activities from 2011 Southwest Outage, and regulatory activity. Additional time will be given during the August 15 meeting to discuss topics from the August 8 MRC Informational Session. Review of Draft Board of Trustees and Board Committees’ Meeting Agendas Chair Helyer reviewed the preliminary list of agenda items, via a slide presentation, for the Board of Trustees and Board Committees’ meetings scheduled for Quebec City, Canada (Exhibit F). The MRC was reminded of the Board’s request to provide policy input on several current issues which include the 2013 BP&B and the recommendations of the SPIG. A letter requesting policy input from

MRC Pre-meeting Conference Call Draft Minutes –– July 10, 2012

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the MRC was distributed on July 10, in advance of the pre‐meeting call. Input from the MRC is requested by August 6, 2012. Schedule of Events for Upcoming Meetings Holly Mann reviewed the schedule of events for the upcoming meetings in Quebec City (Exhibit G). MRC members are encouraged to review all materials for the Board and Board committees’ meetings, once available, and attend as many of these meetings as possible, in advance of the MRC’s discussion on August 15. Committee Nominations Scott Helyer announced two upcoming nomination processes:

1. Proposed membership slate for the Reliability Issues Steering Committee (RISC)

2. Upcoming MRC Officer elections and MRC nominations MRC members were informed that they will receive additional information prior to the August 15 meeting regarding these nomination processes. Meeting Adjourned There being no further business, the call was terminated at 12:20 p.m. Eastern. Submitted by,

Holly Mann Committee Secretary

From: Eleanor CrouchTo: Eleanor CrouchSubject: NERC MEETING Announcement: Member Representatives Committee (MRC) Pre-Meeting Conference Call-July 10, 2012 |

11:00 a.m. - 1:00 p.m. ETDate: Tuesday, June 12, 2012 5:19:59 PM

Meeting AnnouncementMember Representatives CommitteePre-Meeting Conference Call July 10, 2012 | 11:00 a.m. – 1:00 p.m. (Eastern)Dial-in: 800-617-7643No pass code necessary *The agenda for this meeting will be released under a separate cover at a later date.

For more information or assistance, please contact at Eleanor Crouch (via e-mail) or 404-446-2572.

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Member Representatives Committee Pre-Meeting Conference Call July 10, 2012 | 11:00 a.m. Eastern Dial-in: 1-800-617-7643 No pass code necessary Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Announcement Agenda

1. MRC Draft Agendas*

2. Preliminary Agenda Items for the Board of Trustees and Board Committees*

3. Schedule of August Meetings*

4. Request for Policy Input

5. Nominations and Elections

a. Proposed membership slate for the Reliability Issues Steering Committee (RISC)

b. Upcoming MRC Officer elections and MRC nominations

*Background materials included

First Name Last Name Company Are you a member of the MRC?1 Steven Aumann Exelon N2 Kevin Berent North American Transmission N3 William Berry Owensboro Municipal Utilities N4 Terry Bilke M I S O N5 Matt Blizard N/A N/A6 Jim Brenton E R C O T N7 Patrick Brown Canadian Electricity Assoc N8 * Tom Burgess First Energy Y9 Jack Cashin E P S A Y

10 Carol Chinn N/A N/A11 Lam Chung Manitoba Hydro N12 Sylvain Clermont Hydro Quebec Y13 Mark Cole Autry Horton & Cole N14 Christine Connelly-McCullough Duncan Weinberg Genzer & Pembr N15 David Cook N/A N/A16 A J Daig Hydro One N17 Caroline Dupuis Quebec Energy Board Y18 David Dworzak E E I N19 John Falsey Edison Mission Marketing N20 William Gallagher Vermont Public Power Y21 Jennifer Gardner Western Interstate Energy N22 Micheal Gildea N E R C N23 David Goulding N E R C Board of Trustees N24 Jonathan Hayes South West Power N25 Scott Helyer N/A N/A26 Mary Lou Ideus E D P Renewalables U S A N27 Susan Ivey Exelon Y28 Denise James Dominion Energy Marketing Inc N

M R C Pre MeetingReservation Number: 21596884 Reservation Date/Time: 07-10-2012 11:00 ETN

Chair Person: Scott Helyer Total Number of Lines: 58

Company Name: NERC NA ELECT RELIABILITY CORP

29 * Hardev Juj B V A N30 Jim Keller Wisconsin Electric N31 Matt Krastram P G E N32 Mark Lauby N/A N/A33 Holly Mann N/A N/A34 Jason Marshall Aces Power Marketing Y35 Cory McAlister Portland General Electric Y36 Tina McClellan N/A N/A37 Sonia Mendonca N/A N/A38 Susan Morris S E R C N39 Jeff Mueller Public Service Electric Gas Co N40 Paul Murphy I E S O Y41 David Nevius N/A N/A42 Wilket Ng Con Edison N43 Lawrence Nordell Montana Consumer Counsel Y44 Nicholas Occhionero New York State Department N45 Chris Parr K C P L N46 Mike Penstone Hydro One Y47 Harvey Reed N P C C Y48 Bob Schaffeld Southern Co Y49 Katie Schneider S E L N50 Herb Schrayshuen N/A N/A51 Ed Schwerdt N P C C N52 * John Seelke P S E G Y53 Kirit Shah Ameren N54 William Taylor Caltine Y55 John Twitchell S E R C N56 Don Twitty Taps Y57 James Williams Wirab N58 Christopher Wilson Southern Co N

Draft Agenda Member Representatives Committee Informational Session Conference Call and Webinar August 8, 2012 | 11:00 a.m. Eastern Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice Agenda

1. Update on the Recommendations from the Standards Process Input Group (SPIG)

2. 2012 Long-Term Reliability Assessment and Emerging Issues

3. Progress Reports and Informational Updates

a. Risk-Based Compliance Monitoring and Entity Assessments

b. Compliance Enforcement Initiative, including Find, Fix, Track and Report (FFT) Initiative

c. FFT Order - Paragraph 81

d. NERC Compliance Process Bulletin #2012-001: Applicability of PRC-023-1 for Generator Owners

Draft Agenda Member Representatives Committee August 15, 2012 | 1:00-5:00 p.m. Eastern Hilton Quebec 1100, Rene-Levesque Blvd East Quebec, QC Canada G1R 4P3 418-647-6500 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice Consent Agenda

1. Minutes ― Approve

a. July 10, 2012 Conference Call

b. May 8, 2012 Meeting

2. Future Meetings


4. Elections and Nominations

a. MRC Officer and Sector Elections

b. Update from the Board of Trustees Nominating Committee

5. ERO Business Plan and Budget Process

6. Status of SPIG Recommendations and RISC Mandate

a. Nominate Slate for the Reliability Issues Steering Committee (RISC)

7. Status of and Policy Input for Standards Projects

a. Bulk Electric System (BES) Defintion

b. Adequate Level of Reliability (ALR) Definition

c. Status of communications standards

8. Additional Discussion of MRC Informational Session Items, August 8

a. Update on Entity Assessments

b. Compliance Enforcement Initiative, including Find, Fix, Track and Report (FFT)

c. FFT Order - Paragraph 81

Member Representatives Committee Agenda August 15, 2012

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9. Report on Rules of Procedure Process Improvements

10. Follow-Up Activities from the 2011 Southwest Outage

11. Regulatory Update

Member Representatives Committee Pre-Meeting Webinar July 10, 2012

2 RELIABILITY | ACCOUNTABILITY

Objectives

• Review preliminary agenda topics for August 8 Informational Session and August 15 Member Representatives Committee (MRC) meeting.

• Preview proposed list of agenda topics for the Board of Trustees and associated board committee meetings (August 15 and 16).

• Determine adjustments to the August 8 and 15 MRC agendas based on today’s discussion.


Aug 8 – MRC Informational Session

• Recommendations from the Standards Process Input Group (SPIG)

• 2012 Long-Term Reliability Assessment (LTRA) and Emerging Issues

• Progress Reports and Informational Updates Risk-based compliance monitoring and entity assessments

Find, Fix, Track, and Report (FFT) and Paragraph 81

NERC bulletin #2012-001: PRC-023-1


Aug 15 – MRC Quebec City Meeting

• Elections and Nominations

• ERO Business Plan and Budget Process

• Status of SPIG Recommendations and Reliability Issues Steering Committee (RISC)

• Status of and Policy Input for Standards Projects Bulk Electric System (BES) and Adequate Level of Reliability

(ALR) Definitions

Communications standards

• Additional Discussion of August 8 Items

• Rules of Procedure Process Improvements

• Follow-up Activities from Southwest Outage

• Regulatory Update


Board of Trustees

• Committee Membership Appointments and Mandate Amendments

• Standards VAR-002-2, IRO-001-3, PRC-005-2

Communications

Section 1600 data request in response to Order No. 754

Retirement of BAL-004-1

• 2013 BP&B and Associated Assessments

• Rules of Procedure Process Improvements


Board of Trustees

• SPIG Recommendations RISC mandate

Status of other recommendations

• Follow-up on Southwest Outage Recommendations

• Critical Infrastructure Department (CID) Update Cyber Security Risk Maturity Model

ES-ISAC portal

Risk management guidelines

High-Impact, Low-Frequency (HILF) Coordinated Action Plan, Phase II

• Standing and Board Committee Reports

• Forum and Group Reports

Schedule of Events – Industry August 15-16, 2012 — Quebec City, Canada

Wednesday, August 15, 2012

7:30-8:30 a.m.

Room name: Main Ballroom

Corporate Governance and Human Resources Committee OPEN Session

8:30-9:30 a.m.

Room name: Main Ballroom

Standards Oversight and Technology Committee – OPEN Session

9:45-10:45 a.m. Room name: Main Ballroom

Compliance Committee – OPEN Session

10:45 a.m.-Noon Room name: Main Ballroom

Finance and Audit Committee OPEN Session

Noon to 1:00 p.m. LUNCH

1:00-5:00 p.m. Room name: Main Ballroom

Member Representatives Committee – OPEN Session

6:00 p.m.

Location:

Reception

Thursday, August 16, 2012

8:00 a.m.–Noon Room name: Main Ballroom

Board of Trustees Meeting

Hilton Quebec MEETING LOCATION

1100, Rene-Levesque Blvd East Quebec, QC Canada G1R 4P3 418-647-6500

Draft Minutes Member Representatives Committee May 8, 2012 | 1:00–4:30 p.m. ET Westin Arlington Gateway 801 North Glebe Road Arlington, Virginia 22203 Chair Scott Helyer called to order the North American Electric Reliability Corporation (NERC) Member Representatives Committee (MRC) meeting on May 8, 2012 at 1:00 p.m., ET. The meeting announcement, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. NERC Antitrust Compliance Guidelines and Public Meeting Notice Chair Helyer called attention to the NERC Antitrust Compliance Guidelines and the public meeting notice. Any questions regarding these guidelines or notice should be addressed to NERC’s General Counsel, David Cook. Introductions and Chair’s Remarks Chair Helyer declared a quorum present with the following recognized proxies:

• Barry Lawson for Eric Baker and Michael Smith – Cooperative

• Bill Gallagher for Terry Huval – Transmission Dependent Utility

• Charles Acquard for Larry Nordell – Small End-Use Customer

• Stacy Dochoda for Gordon Gillette – Regional Entity (non-voting)

• Gilbert Neveu for Jean-Paul Théorêt – Canadian Provincial (non-voting)

Chair Helyer acknowledged and welcomed Vice Chair Carol Chinn, the NERC Board of Trustees, Commissioners Cheryl LaFleur and Philip Moeller1

, Federal Energy Regulatory Commission (FERC), and Assistant Secretary of Energy Pat Hoffman, Department of Energy (DOE). Chair Helyer also recognized the policy input provided by the MRC and stakeholders at the request of John Q. Anderson, chair of the NERC Board of Trustees.

1 Commissioner John Norris attended the meeting following Commissioner Moeller’s departure.

MRC Draft Minutes May 8, 2012

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Minutes The MRC approved the draft minutes of its March 29, 2012 conference call and February 8, 2012 meeting (Exhibits D and E). Remarks from Gerry Cauley, NERC President and CEO President Cauley recognized the MRC’s submission of policy input and strong support for a number of current ERO initiatives. One notable initiative was the release of the 2011 Southwest Outage Report, which serves as a model for successful collaboration between FERC, NERC, and others involved in the inquiry of this event. The report points to a number of significant findings, expected remediation actions, and lessons learned that are relevant throughout industry and which should help ensure reliability institutions, processes, and standards remain effective and continue to improve. Another initiative noted was the recent work to improve the development of timely standards that produce real reliability results. President Cauley stated he is encouraged by the proposal of the Standards Process Input Group (SPIG) and the chain of accountability now established between FERC, Canadian regulators, NERC Board of Trustees, the ERO Enterprise, and other stakeholders. The real measure of success for this initiative will be determined during the implementation phase of the five SPIG recommendations. Lastly, President Cauley shared that he is pleased with the recent March 15 Order in which FERC accepted NERC’s petition requesting approval of the Find, Fix, Track and Report (FFT) initiative and accompanying guidance. NERC will continue to work with the Regions and train staff on minimizing risks, setting an initial level of discretion, and sustaining, growing, and expanding the FFT initiative without jeopardizing the regulatory assurance that ensures focus on the right risks and priorities. Nominations Board of Trustees Nominating Committee Chair Helyer announced the annual request for MRC participation on the Board of Trustees Nominating Committee (BOTNC). Jan Schori will chair the BOTNC in its search to fill two trustee terms, for John Q. Anderson and Tom Berry, scheduled to become vacant in February 2013. Three members will be selected, along with Chair Helyer and Vice Chair Chinn, as part of the MRC’s proposed slate to the BOTNC.


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Electricity Sub-Sector Coordinating Council The MRC approved the proposed slate of the following executive members to the Electricity Sub-Sector Coordinating Council (ESCC), effective July 1, 2012:

Paul Murphy, Independent Electricity System Operator – Subsequent term expires June 2013 Jim Torgerson, UIL Holdings Corporation – Subsequent term expires June 2013 John Procario, American Transmission Company, LLC – Subsequent term expires June 2014 Kevin Wailes, Lincoln Electric System – Initial term expires 2014 Duane Highley, Arkansas Electric Cooperatives, Inc. – Initial term expires 2014

The MRC requested that the ESCC consider equal representation from the various interconnections. President Cauley, who chairs the ESCC, confirmed that equal representation is desired among the membership and the MRC’s suggestion will be considered during future nomination periods. Chair Helyer noted that the Board of Trustees is being asked to consider a procedural adjustment to the ESCC charter that would allow the timeframe for the annual nomination process of the executive member slate to better coincide with the MRC’s quarterly May meeting dates. The ESCC charter currently states for the process of selecting the CEO-level executives: Annually, starting June 1, the NERC Member Representatives Committee (MRC) will accept nominations for three weeks ending June 21 (or the next business day), for qualified individuals to serve as executive members on the ESCC. 2013 NERC Business Plan and Budget President Cauley introduced the 2013 business plan and budget development process. Michael Walker, senior vice president and chief financial and administrative officer, reviewed the 2013 resource and financial projections and schedule for the remainder of the cycle. Mr. Walker cited improvements to the 2013 planning cycle, including the development of multi-year objectives and budget projections, earlier collaboration with the Regions, and production of a common strategic plan. Key deliverables and resource drivers include:

a. Working with industry to implement standards process improvements to address efficiency, timeliness, and effectiveness;

b. Focusing on issues having the most significant impact on reliability;

c. Developing risk control strategies;

d. Facilitating the transfer of best practices, lessons learned, and industry innovations; e. Enhancing bulk power system threat and vulnerability information sharing through the

Electricity Sector Information Sharing and Analysis Center (ES-ISAC); and

f. Expanding training and education programs.


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The following questions and comments were provided by the MRC regarding this topic:

• The transparency that NERC has offered is commendable, but the level of detail is not consistent with the amount of time allowed for review and comment.

• It is encouraging to hear about leveraging tools and programs such as FFT to reduce costs and resource pressures at NERC and among the Regions.

• Compliance and enforcement budgets should remain flat for the next year.

• The three-year budget planning horizon should help highlight which items might be reduced this year, but potentially increased next year. The three-year planning horizon should also help focus most on the things that matter to reliability.

• It is difficult to provide policy advice on the budget and business plan based on the level of detail provided. It seems that the industry should be providing advice on the strategic focus and overall priorities for the year. Even though understanding the cost of delivery is important, it seems that a lot is lost in the budgetary details.

• What are NERC’s longer range objectives with respect to the ERO and the Regions over the next three years? What are the driving forces and direction behind moving the organization through the next three years? Is there a way to promote greater visibility and collaboration of these strategic objectives over the next three years?

President Cauley confirmed that the MRC is asking for a better strategic view of where NERC is trying to get in the next three years. There is a strong obligation to identify and articulate risks and to make sure these risks are resolved. NERC does not have to be the entity that provides the solution to every risk. There needs to be continued dialogue regarding what solutions and achievements can be owned and accomplished by others. Additional Discussion of the May 1 MRC Informational Session Items Chair Helyer asked for any additional discussion needed on the agenda items from the May 1 MRC information webinar session. The following comments were provided by the MRC regarding these various topics: Bulk Electric System (BES) Definition, Phase 2

• Members cautioned against creating another burden for the Regional Entities when defining the exception process. Anything coming forward needs to be able to be implemented within the framework of budget and staffing.

• Members encouraged the approval of Phase 1.


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Definition of Adequate Level of Reliability (ALR)

• A draft definition paper and several supporting documents were recently made available for industry comment. It is still unclear how a standard drafting team(SDT) is supposed to handle and apply the various documents that are currently available for review.

• These documents are intended to raise awareness of overall reliability objectives and performance outcomes. The first step of the SDT is to think through the reliability objectives that are trying to be accomplished to determine if the scope is properly defined and the requirements are aligned with the goals. The development of a standard is only one element or strategy used to accomplish higher level objectives.

• Another important consideration is whether the current reliability principles can be retired or modified to sync with the new reliability objective.

Chair Helyer reported that the former BES/ALR Task Force will be dismissed until and unless a further need arises. Risk-Based Compliance Monitoring and Entity Assessments

• It is unclear how reliability standard audit worksheets (RSAWs) will negate the need for compliance application notices (CANs). RSAWs should not be used for alternative reasons in the compliance realm.

Mike Moon, director of compliance operations, NERC, confirmed that the RSAW is the best tool to offer appropriate, clarifying guidance to facilitate compliance. The CAN is not the optimal solution. The RSAWs are an essential tool that both auditors and the industry use. Better utilization of RSAWs should help alleviate the need for CANs.

• There is large support for the risk-based compliance monitoring approach; however, the criteria have not been made available for review or comment. It is unclear how this initiative will be applied consistently across the Regions.

• Specialized attention may need to be given to Canada where one size of assessment may not fit all.

Mr. Moon confirmed the criteria and template are not yet finalized and available for distribution. However, there are two outreach efforts underway:

1. The NERC Compliance and Certification Committee is providing a broad view of how to set up the template; and

2. Registered entities participated in four focus groups to share details regarding their compliance history and assessment functions. The intent is to promote the individual assessment of an entity and further their work with the Region. Risk is not consistent among all entities so the common template should only be considered as a base starting point.


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Status of Current Standards Projects At the previous request of the MRC, Herb Schrayshuen, vice president of standards and training, NERC, provided an update on several ongoing standards projects. Status of Regional Standards Development Programs Tim Gallagher, ReliabilityFirst (RFC), reported there are only seven regional standards under active development. Two of the seven have been approved by the NERC Board of Trustees. The majority of the regional standards developed have been in response to fill-in-the-blank standards. The regions believe that these standards are consistent with the NERC standards even though additional detail or implementation steps may be included based on their stakeholders’ response. The elimination of regional standards is dependent upon the development of NERC-wide solutions to the fill-in-the-blank standards. Encouraging progress has been made in this area with the underfrequency load shedding project. The MRC shared concern that there are no natural seams that limit specific regional standards from exposing a full interconnection to reliability risks. Intuitively, the majority want to migrate away from using regional standards. Status of Underfrequency Load Shedding (UFLS) Activities Mr. Schrayshuen confirmed that FERC issued an order on the UFLS Standard on May 8. The purpose of the PRC-006 standard is to arrest declining frequency after a disturbance, assist in the recovery following under-frequency events, and provide load preservation measures. The North American standard contains variances for WECC and the Quebec Interconnection. The conclusion of the SDT was to focus on the planning coordinator as the entity to manage the process. Historically, the Regions have been managing this process so a transition continues to be underway for many of the Regions. A regional report of activities was provided as part of the agenda package for this meeting. Status of Operating Communications Protocols Mr. Schrayshuen reported the interpretation for COM-002, Communications and Coordination, was approved and is on hold to be sent to FERC pending the completion of several other activities that include: The current posting and industry review of the COM-003, Operating Personnel Communication Protocol, the completion and approval of the NERC Operating Committee Reliability Guideline, a revised RSAW and petition for the COM-002 Interpretation. The following comment was provided by the MRC members regarding this project:

• The COM-003 combined with the Transmission Operators (TOP) standards highlights a potential process issue. The TOP standards assumed a certain definition would be written for a reliability directive. The reliability coordination drafting team was writing that definition and now the posting of the COM-003 actually rewrites that definition, without the approval of the TOP standards.


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Mr. Schrayshuen recommended that the Standards Committee review this concern during an upcoming meeting to determine a solution. 2012 State of Reliability Report Mark Lauby, vice president of reliability assessment and performance analysis, NERC, provided a summary of NERC’s independent view of the state of reliability. The report was issued in conjunction with the Planning Committee and the Performance Analysis subcommittee. Additional support and comment was received by the Operating Committee and the MRC. There were six key findings:

1. Reliability of the bulk power system remains adequate.

2. Frequency response is stable with no deterioration.

3. Protection system misoperations are a significant reliability issue.

4. Equipment failure warrants further analysis.

5. Resource mix changes necessitate new metrics.

6. More data and research is needed. Recommendations of the 2011 Southwest Outage Dave Nevius, senior vice president, NERC, and Heather Polzin, Office of Enforcement, FERC, provided a summary of the joint inquiry, sequence of events, and the findings and recommendations from the September 8, 2011 cascading outage in the Pacific Southwest. A link to the report can be found here: 2011 Southwest Outage Report.

Culture of Reliability Excellence Tom Bowe, executive director of reliability and compliance, PJM Interconnection, provided a presentation on the activities related to PJM’s culture of reliability excellence. Recommendations of the Standards Process Input Group (SPIG) Chair Helyer announced the opportunity to review the recommendations of the SPIG and announced that the Board of Trustees Standards Oversight and Technology Committee will meet immediately following the MRC meeting to provide for continued discussion of this issue. In February 2012, the Board of Trustees requested that the MRC prepare recommendations on improving the standards development process. The SPIG was formed to address this task through gathering feedback and input and reporting back recommendations to the MRC for approval and delivery to the Board of Trustees.

http://www.nerc.com/fileUploads/File/News/AZOutage_Report_01MAY12.pdf�


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The following questions and comments were provided by the MRC regarding this topic: Recommendation #1: American National Standards Institute (ANSI)

• This recommendation is important to Canadian members. It provides the right safeguards.

• Is there an opportunity that we are missing to meet the maximum requirements? Should this be adjusted to read “at a minimum, there should be an ANSI process…”? Are we unnecessarily encumbering the process by exceeding the minimum requirement, where necessary?

Chair Helyer clarified that this statement aligns more with the expectation that NERC will provide a response to all comments submitted, adhering to the minimum requirements versus trying to apply the ANSI process every step of the way through commenting and balloting. Recommendation #2: Reliability Issues Steering Committee (RISC)

• It will be important to articulate the role, responsibility, and function of the high-level RISC since it may assume a portion of activities currently assumed by other committees. A mandate will be necessary to avoid overlap. Need to be careful not to overburden the anticipated members who may also serve on other technical committees.

• It is unclear how the RISC will save time and make the standards development process quicker and more efficient. How much time will it take for the RISC to act on nominations?

Chair Helyer recognized the need for a front-end process to evaluate, clarify, and potentially reduce the actual number of issues that are being pushed into standards development. Currently, a lot of Standard Authorization Request [SAR(s)] enter, and potentially burden, the process. There are issues that may not warrant the development of a standard that can be addressed through other alternative solutions. There will be more thought going into the beginning of this cycle, which will hopefully cut down on the amount of invested resources and overall workload that is required. The intent is to better manage what is going into the standards process for better throughput of solutions. There are details that still need to be considered once we decide this is the route to pursue. President Cauley recognized that RISC is a new and different function that will rely on collective brainpower, facts, and risk assessments to form justifications and recommendations for taking action. The RISC will prioritize key issues and provide the regimented focus for documenting and tracking actions towards a solution and benefit to reliability. This is not a replacement of the SAR, but rather a new path for steering the agenda of the ERO and instilling accountability. The key is to bring together all of the standing committees to support this new initiative.


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• The RISC seems to allow stakeholders, especially those with limited resources, to be more focused on reliability gaps. It will hopefully focus on what needs to be done to satisfy the gap. We are evolving past just putting standards in place for the sake of having standards. The RISC also has the potential to comb through standards to determine the subset of what is important to focus on for reliability.

• Will the RISC be expected to develop a project plan with milestones and targets to indicate a measurable path to pursue for any given issue to ensure there is some tracking and oversight for accomplishing a solution?

• The concept of the RISC sounds good, but a flowchart is needed to show relationships and illustrate how the RISC is assisting and facilitating the current process. There needs to be reassurance that the RISC will not assume the role of “gatekeeper”.

• It is unclear if the RISC will just have the authority to advise the board or to actually perform certain actions. The front-end process is equally confusing regarding how nominations enter the RISC.

President Cauley clarified that the front-end process is not exclusive and the only route for identifying risks. The front-end process has more to do with how the ERO is sponsoring issues that need to be defined, prioritized, vetted and tracked. The process does not preclude others from performing similar nomination activities or working on similar technical issues. The risk portfolio of the ERO needs prioritization and board visibility. Recommendation #4: Standards Product Issues

• A lot of the standards development process is assumed to be in the hands of the stakeholders. Has there been enough consideration for what will be required for stakeholder implementation versus which things will actually require board approval? Once an item or issue has received board approval, it is much more difficult to modify or adjust at a later date. There needs to be consideration for stakeholder involvement and flexibility.

President Cauley recognized that there may be confusion with the wording of the recommendation. The Board of Trustees may not take ownership for each recommendation of the SPIG or the RISC, but instead decide what standing committee will have primary responsibility. So this will still include stakeholders via the input of committees and the MRC.

• Encouraged by the proposed alignment with the RSAWs. Compliance guidance structured in the RSAWs allows for minimizing and even eliminating Violation Severity Leves (VSLs) and other products in use.

• All of the recommendations seem like they are standards-related so it is still unclear what might go through the RISC besides issues/projects geared towards standards-related outcomes.


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President Cauley recognized that all of the SPIG’s recommendations except for #2 involving the RISC, are directly linked to standards development. This unfairly presumes that all reliability risks end with standards. There are options that may not be communicated in these five recommendations that still need to be developed, perhaps with the formation of the RISC.

• Is the RISC linked to the risk-based assessment? President Cauley clarified that the risk-based assessment is in the compliance monitoring arena regarding individual entity assessment, the quality of internal controls, etc.

• Seems like this recommendation struggles with the material impact to the bulk power system (BPS). The retirement of standards that are no longer needed sounds good, but a lot of the standards we have in place are based on lessons learned and as we get better at preventing outages and lengthening time between major events we need to ensure that we do not become complacent and forget why we are doing certain things and not getting rid of things that we need. It will be hard to define “what is no longer needed for an adequate level of reliability.”

• Remember that the standards are made up of requirements so we may need to just consider adjustments to the requirements and not the entire standard itself.

Recommendation #5: Standards Development Process and Resource Issues

• Regarding the “no vote”, there needs to be caution when reviewing the comment and determining whether it is good enough for the no vote to count. We need to consider who makes the decision, what is the basis for how is it determined, etc. There is also need for additional clarity regarding a voting record for each entity. It is unclear why this type of list is needed and what it will be used for.

Chair Helyer confirmed that the “no vote” option is to identify what the problem is perceived to be and why the no vote is cast. A new format may be necessary so the voter can select from a list of pre-determined reasons for why they are voting no. There will always be the option of providing comments. President Cauley confirmed that standards development is the responsibility of all among the industry. With responsibility comes accountability for the decisions made regarding standards development.

• Strong agreement with the proposed composition of the SDTs, especially the involvement of a project manager and facilitator. This role is a key contributor to a more efficient and timely process.


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• A detailed quality review is typically performed at the back end of the standards process, but we need to strive towards conducting this review “during” or “as we go along” in the process. The quality goes in before the name goes on.

On a motion by Tom Burgess with a second by William Taylor, the MRC approved advancing the SPIG’s report and recommendations to the Board of Trustees for further consideration, additional tasking, and further development of the RISC. August 15, 2012 Meeting and Future Meetings The following are future MRC meeting dates and locations:

• August 15–16, 2012 – Quebec City, Canada

• November 6–7, 2012 – New Orleans, LA

• February 6–7, 2013 – San Diego, CA

• May 8–9, 2013 – Philadelphia, PA

• August 14–15, 2013 – Montreal, Canada

• November 6–7, 2013 – Atlanta, GA

• February 5–6, 2014 – Phoenix, AZ Update on Regulatory Matters Chair Helyer invited MRC members with questions or concerns regarding additional regulatory matters to meet with David Cook, senior vice president and general counsel, NERC, at the conclusion of the meeting. Adjournment There being no further business, the meeting terminated at 5:00 p.m. ET. Submitted by,

Holly Mann MRC Secretary

From: Eleanor CrouchTo: Eleanor CrouchBcc:

Subject: NERC ANNOUNCEMENT: Member Representatives Committee (MRC) and Board of Trustees (BOT) Meetings-May 8-9, 2012 |Arlington, VA

Date: Friday, March 09, 2012 12:09:00 PM

Meeting AnnouncementMember Representatives Committee (MRC)Board of Trustees (BOT)

May 8-9, 2012 | Arlington, VA Click Here for: Meeting Registration

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When making your hotel reservation, please be sure to mention “NERC” to get the preferredrate and ensure your reservation is credited to the NERC room block. The hotel will chargeNERC a penalty if the total rooms blocked for this event are not picked up. Also, if you use atravel agency for your travel plans, please make sure the agency mentions NERC. For moreinformation or assistance, please contact Eleanor Crouch at [email protected] or (404)446-2572.

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Agenda Member Representatives Committee May 8, 2012 | 1:00-4:30 p.m. Eastern Westin Arlington Gateway 801 North Glebe Road Arlington, Virginia 22203 703-717-6200 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice Consent Agenda

1. Minutes* – Approve

a. March 29, 2012 Conference Call

b. February 8, 2012 Meeting

2. Future Meetings* – Information


4. Nominations*

a. Recommend Slate of MRC Members to Serve on the Board of Trustees Nominating Committee

b. Nominate Slate for the Electricity Sub-Sector Coordinating Council (ESCC)

5. 2013 NERC Business Plan and Budget – Information

6. Additional Discussion of MRC Informational Session Items, May 1* – Discussion

a. Bulk Electric System (BES) Definition, Phase 2

b. Definition of Adequate Level of Reliability (ALR)

c. Risk-Based Compliance Monitoring and Entity Assessments

d. Compliance Enforcement Initiatives

7. Status of Current Standards Projects – Discussion

a. Status of Regional Standards Development Programs*

b. Status of Underfrequency Load Shedding (UFLS) Activities*

c. Status of Operating Communications Protocols*

d. Standards for Board of Trustees Adoption, May 9 [Reference: Board of Trustees Agenda Item 6]

Exhibit B

Member Representatives Committee Agenda May 8, 2012

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8. 2012 State of Reliability Report* – Information

9. Recommendations from the 2011 Southwest Outage* – Information

10. Culture of Reliability Excellence* – Tom Bowe, PJM – Discussion

11. Regulatory Update* – Information

12. Recommendations of the Standards Process Input Group (SPIG)* – Discussion

a. Further Discussion on Recommendations of the SPIG in Standards Oversight and Technology Committee Meeting (to follow MRC Meeting)

*Background materials included.

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List of Attendees

Member Representatives Committee Meeting Arlington, VA

May 8, 2012

Member Representatives Committee Chairman Scott Helyer

Vice Chair Carol Chinn

Investor-Owned Utility Thomas Burgess

Investor-Owned Utility Robert Schaffield

State/Municipal Utility Timothy Arlt

State/Municipal Utility John DiStasio

Cooperative Utility Eric Baker (Proxy: Barry Lawson)

Cooperative Utility Michael Smith

Federal/Provincial Utility Julius Penstone

Federal/Provincial Utility Anthony Montoya

Federal/Provincial Utility Lorne Midford

Federal/Provincial Utility Sylvain Clermont

Transmission Dependent Utility John Twitty

Transmission Dependent Utility Terry Huval (Proxy: Bill Gallagher)

Merchant Electricity Generator Maggie Powell

Merchant Electricity Generator William Taylor III

Electricity Marketer Jason Marshall

Electricity Marketer Jack Cashin

Large End-Use Electricity Customer Michelle D’Antuono

Large End-Use Electricity Customer John A. Anderson

Small End-Use Electricity Customer Larry Nordell (Proxy: Charles Acquard)

Small End-Use Electricity Customer Charles Acquard

ISO/RTO Paul Murphy

ISO/RTO Terry Boston

Regional Entity (Voting) Jeff Gust (MRO)

Regional Entity (Voting) Harvey Reed

State Government Thomas Dvorsky

State Government Robin Lunt

Canadian Provincial Jean-Paul Théorêt (Proxy: Gilbert Neveu)

Canadian Federal Amitabha Gangopadhyay

U.S. – Federal Pat Hoffman

U.S. – Federal Joseph McClelland

Exhibit C

List of Attendees 2 Member Representatives Committee Meeting May 8, 2012

Regional Entity Gordon Gillette (FRCC) (Proxy: Stacy Dochoda)

Regional Entity Ed Tymofichuk (MRO)

Regional Entity Harvey Reed (NPCC)

Regional Entity Susan Ivey (RFC)

Regional Entity Maureen Borkowski (SERC)

SPP RE Ron Ciesiel (SPP RE)

Regional Entity Lane Lanford (TRE)

Regional Entity Constance White (WECC)

Secretary Holly Mann

Board of Trustees Chairman John Q. Anderson

Vice Chair Bruce Scherr

Member Vicky Bailey

Member Paul Barber

Member Thomas Berry

Member Janice Case

Member Gerry Cauley

Member Fred Gorbet

Member David Goulding

Member Ken Peterson

Member Jan Shori

Member Roy Thilly

Regional Executives MRO Dan Skaar

NPCC Edward A. Schwerdt

ReliabilityFirst Tim Gallagher

SPP RE Ron Ciesiel

WECC Mark Maher

Guests SPP Alice Wright

APPA Allen Mosher

WAPA Anthony Montoya

Edison Electric Barbara Hindin

NRECA Barry Lawson


MISO Bill Phillips

USE Bob Dintelman

Southern Company Bob Schaffeld

SERC Carter Edge

Georgia System Operators Corporation Clay Smith

WECC Connie White

WPPI Dan Brent

EEI David Batz

NERC David Cook

EEI David Dworzak

NERC David Nevius

Texas RE Derrick Davis

PSE&G Don Holdsworth

NERC Earl Shockley

Entergy Ed Davis

NERC Ed Kichline

KG&E-KU LLC Ed Staton

NERC Elizabeth Heenan

SPP F. John Meyer

FMPA Frank Geoffrey

NERC Frazaneh Tafreshi

SPP RE Gerry Burrows

Lafayette Utilities System Gini Ingram

Tampa Electric Company Gregory Ramon

BPA Hardev Juj

NPCC Harvey J. Reed

NERC Herb Schrayshuen

The Dayton Power and Light Hertzel Shamash

Natural Resources Canada Ivan Harvie

Nebraska Public Power Jake Burger

Edison Electric Institute James Fama

WIEB/WIRAB James M. Williams

Arizona Public Service Company Jana Van Ness

NERC Janet Sena

ReliabilityFirst Jason Blake

ACES Power Marketing Jason Marshall


NERC Jason Wang

NERC Jeff Hicks

PSE&G Jeff Mueller

ReliabilityFirst Corp. Jeffrey Mitchell

Oncor Electric Delivery Jen Fiegel

Northeast Power Coordinating Council Jennifer Budd Mattiello

MRO Jim Burley

Canadian Electricity Association Jim Burpee

NYISO Jim Castle

Wisconsin Electric Jim Keller

WIEB Jim Williams

Residential Utility Consumer Office Jodi Jerich

Ameren Joe Power

Associated Electric Cooperative John Bussman

PSEG Services Group John Seelke

SERC John Twitchell

TAPS John Twitty

CPS Jose H. Escamilla

Madison Gas and Electric Company Joseph Depoorter

Schweitzer Engineering Laboratories Katie Schnider

Sempra Generation Katy Wilson

NERC Ken Lotterhos

ERCOT ISO Ken McIntyre

LG&E-LU LLC Ken Sheridan

Detroit Edison Kent Kujala

SERC Kevin Berent

NERC Kimberly Mielcarek

FERC Larry Gasteiger

NERC Laura Hussey

SMUD Laura Lewis

Montana Consumer Counsel Lawrence Nordell

FRCC Linda Campbell

Dominion Lou Oberski

Georgia System Operations Corp Lloyd S. Snyder

Dominion Resources Lou Oberski

Dominion Louis Slade


Exelon Maggy Powell

SERC Marissa Sifontes

Competitive Power Venture Mark Bennett

NERC Mark Lauby

NERC Marvin Santerfeit

NERC Matt Blizard

Ameren Maureen Borkowski

NERC Michael DeLaura

MRO Miggie Crambilt

NERC Mike Moon

NERC Mike Walker

National Grid Nabil Hitti

Duke Energy Nelson Peeler

Canadian Electricity Association Patrick Brown

Florida Reliability Coordinating Council Peter Heidrich

WECC Rachel Sherrard

New York Power Authority Randy Crissman

NERC Rebecca Michael

ReliabilityFirst Robert Wargo

SPP RE Sara Patrick

NERC Scott Halleran

SERC Scott Henry

NERC Stacey Tyrewala

FRCC Stacy Dochoda

Exelon Steve Naumann

NERC Consultant Stuart Brindley

SJC Energy Consultant, LLC Susan Court

APPA Sue Kelly

Exelon Susan Ivey

TRE Susan Vincent

National Energy Board, Canada Tab Gangopadadhyay

WECC Taud Olsen

Midwest ISO Terry Bilke

Santee Cooper Terry Blackwell

Southern Company Terry Coggins

Nebraska Public Power District Tim Arlt


NERC Tina McClellan

PJM Tom Bowe

NATF Tom Galloway

NERC Tracy Ruffin

NERC Wanda Peoples

NERC Willie Phillips

Minutes Member Representatives Committee Pre-Meeting Conference Call March 29, 2012 | 3:00 p.m. Eastern Dial in: 800-743-4304 No pass code necessary Chair Scott Helyer convened a duly‐noticed open meeting by conference call of the North American Electric Reliability Corporation’s Member Representatives Committee (MRC) on March 29, 2012 at 3:00 p.m. Eastern. The meeting announcement, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. MRC membership attendance/roll call was not necessary since no quorum was required. NERC Antitrust Compliance Guidelines and Public Meeting Notice Holly Mann, assistant to the NERC president and CEO, and committee secretary, directed the participants’ attention to the NERC Antitrust Compliance Guidelines and the public meeting notice. Review of May 8, 2012 Draft MRC Agenda Chair Helyer reviewed the preliminary agenda for the upcoming May 8, 2012 MRC meeting in Arlington, VA (Exhibit D).

• Topics for discussion will include: regional standards development, underfrequency load shedding, operating communications (COM‐002, COM‐003, technical guidance), Rules of Procedure changes, 2011 Southwest Outage, and the progress of the Standards Process Input Group (SPIG).

• The Standards Oversight and Technology Committee will meet immediately following the MRC on May 8 to provide additional discussion of the recommendations of the SPIG.

• Tom Bowe, executive director, reliability and compliance, PJM Interconnection, will present on the Culture of Reliability Excellence.

• Additional time will be given to discuss the May 1 MRC Informational Session, which will include: Bulk Electric System (BES) and Adequate Level of Reliability (ALR) definitions, entity assessments, demand response availability, summer assessment conclusions, and Find, Fix, Track and Report (FFT) initiative.

Exhibit D

MRC Pre-Meeting Minutes March 29, 2012

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Review of May 9, 2012 Draft Board of Trustees (Board) Agenda Chair Helyer reviewed the preliminary agenda for the May 9, 2012 BOT meeting in Arlington, VA (Exhibit E). The MRC was reminded of the Board’s upcoming request to provide policy input on several emerging issues. A letter requesting policy input from the MRC will be distributed on April 6. Schedule of Events for Upcoming Meetings Chair Helyer reviewed the schedule of events for the upcoming MRC, Board, and Board Committees meetings (Exhibit H). MRC members were encouraged to review all materials for the MRC, Board, and Board committee meetings and attend as many of these meetings as possible, in advance of the MRC’s discussion on May 8. Committee Nominations Holly Mann announced two upcoming nomination processes:

1. MRC members for the Board Nominating Committee

2. CEO executive slate for the Electricity Sub‐Sector Coordinating Council (ESCC) MRC members were informed that they will receive additional information prior to the May 8 meeting regarding these nomination processes. Meeting Adjourned There being no further business, the call was terminated at 4:00 p.m. Eastern. Submitted by,

Holly Mann, Committee Secretary

Minutes Member Representatives Committee (MRC) February 8, 2012 | 1:00–5:00 p.m. MT Arizona Grand Resort 8000 S. Arizona Grand Parkway Phoenix, AZ 85044 Chair Scott Helyer called to order the North American Electric Reliability Corporation (NERC) Member Representatives Committee (MRC) meeting on February 8, 2012 at 1:00 p.m., MT. The meeting announcement, agenda, and list of attendees are attached as Exhibits A, B, and C, respectively. NERC Antitrust Compliance Guidelines and Public Meeting Notice Chair Helyer called attention to the NERC antitrust compliance guidelines and the public meeting notice. Any questions regarding these guidelines or notice should be addressed to NERC’s general counsel, David Cook. Introductions and Chair’s Remarks Chair Helyer declared a quorum present with the following recognized proxies:

• Tom Bowe for Terry Boston – ISO/RTO

• Bill Gallagher for Terry Huval - Transmission Dependent Utility

• Jodi Jerich for Charles Acquard – Small End-Use Customer

• Del Smith for Robin Lunt – State Government

• Linda Campbell for Gordon Gillette – Regional Entity (non-voting)

• Gilbert Neveu for Jean-Paul Théorêt – Canadian Provincial (non-voting) Chair Helyer acknowledged and welcomed Vice Chair Carol Chinn, six new members to the MRC, and attending staff from the Federal Energy Regulatory Commission (FERC). Chair Helyer also recognized the policy input provided by the MRC and stakeholders at the request of John Q. Anderson, chair of the NERC Board of Trustees. Minutes The MRC approved the draft minutes of its November 2, 2011 meeting and January 12, 2012 pre-meeting conference call (Exhibits D and E).

Exhibit E

MRC Draft Minutes February 8, 2012

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Election of Board of Trustees (BOT) Dave Goulding, chair of the nominating committee, provided a report and recommendation for the re-election of three NERC board members for the class of 2015. Chair Helyer called for a vote of the MRC for the re-election of Ken Peterson, Bruce Scherr and Jan Schori. Chair Helyer confirmed a two-thirds affirmative vote from eligible members and congratulated the returning members of the NERC board of trustees. Welcome to Phoenix Dave Areghini, retired associate general manager for Salt River Project, welcomed participants to Phoenix and provided opening remarks regarding the advancement of the ERO Enterprise concept for the purpose of strengthening Reliability. Mr. Areghini shared that he believes the greatest deficiency facing the ERO is the inability to successfully quantify progress, use appropriate metrics, and leverage resources that exist among the industry. NERC and the Regions are encouraged to reach out to the industry and promote training and practice that reinforce our culture of reliability. Remarks from Gerry Cauley, NERC President and CEO Mr. Cauley recognized the policy input received by the board and shared his appreciation for the continued opportunities for dialogue with the MRC and industry. There were a number of accomplishments by NERC and the ERO Enterprise in 2011 which utilized support from the Industry; these included the filing with FERC of the Bulk Electric System (BES) definition, continued prioritization of standards, completion of GridEx, and progression of the find, fix, track and report (FFT) initiative. Additional investment in the events analysis process and procedure also proved successful for 2011. Update on ERO Enterprise Strategic Planning and Corporate Goals The current ERO Enterprise Strategic Plan (2012-2015) includes goals that span three major focus areas:

1. Standards and compliance

2. Risks to reliability

3. Coordination and collaboration

The 2012 goals are structured around achieving efficiency and effectiveness, a risk-management focus, and accomplishable outcomes and results. The NERC standards need to be results-based with effective compliance monitoring and internal controls. NERC is in the process of confirming weights for each of the three focus areas and the multiple corporate performance metrics associated with each since they are not all equal in the eyes of NERC, the regions, industry or FERC. The goals, objectives and measures will continue to be scaled over the upcoming weeks based on importance, relevance, and timeliness of each. A more refined version is


3

expected to be delivered to the board Corporate Governance and Human Resources Committee by the end of the month.

Mr. Cauley also recognized opportunities exist to collaborate with registered entities and the forums to analyze data and align risks and cause codes. The forums and others among the industry could also take on the responsibility of identifying risks and analyzing data to determine trends and patterns. As the ERO, NERC is obligated to identify and prioritize certain risks and patterns between identifying risks and fixing them there is a lot of work to be done.

Mr. Cauley confirmed NERC’s intent to be more transparent in its corporate year-end report for 2012. Standards Development Process Improvements Mr. Cauley wants to introduce, in 2012, another opportunity to seek clarification on the overall structure and timeliness of the standards development process to ensure greater efficiency and quality of results. The ERO must equally consider the weight of compliance on those entities that have to implement and meet the requirements of standards. In the past, additional time has been allocated to address improvements to the administrative processing, balloting, etc. It is now the time to address several additional issues in the upcoming year:

1. Process - Determining how to address the efficiency of the process by breaking the existing mold for how we develop standards. Are there other options and alternatives for developing a successful development cycle that will improve a timely standards process?

2. Resources - Maximizing the use of appropriate resources. Protecting the right of all stakeholders involved while deriving the necessary talents to comprise the drafting team and ensuring the correct legal, writing, and enforcement support for standards development.

3. Governance – Determining if sustainable governance is in place to produce adequate reliability through standards development. Encouraging the ERO Enterprise to continue identifying risks and setting the priorities and timeline for producing a standard through the use of an improved process.

Chair Helyer recognized the MRC has a role to support and advise the board on the issue of standards development. Various comments were received in writing prior to the meeting, but the following comments were provided by the MRC members regarding this topic:

• The current process lacks a clear scope and facilitation framework for the drafting team.

There need to be clear rules for everyone who participates in a standard drafting team (SDT), including NERC and FERC staff.

The team structure currently lacks sufficient policy advisors and technical writers.


4

NERC should serve in a guiding role for the team, as a facilitator to address the scope, manage the schedule, and to maintain specific issues.

• Concerns were raised about the need to have the industry included in the governance of the standards development.

• NERC is not the only organization that has tried to master the development of standards. NERC should benchmark its process against other organizations that set standards. MRC should take a role in leading the effort to revise the standards development process. The board relies on the MRC for this involvement.

• The MRC should ensure that input from stakeholders remains at the forefront and be careful to remember the international collaboration and policy input from CEA.

• Attention should be given to the comments and recommendations of the trades. There needs to be a senior group of leaders to consider other process optimization, such as ANSI’s process, as well keeping the industry input.

• The development of FFT process has been a success and should be trusted. Suggestions were made for the MRC to form a small steering group to provide policy input to the BOT regarding improvements to the Standards development process. Chair Helyer suggested the MRC form a small steering group under the invitation of Chair Anderson and the board. Participants may include MRC members, a Canadian representative, chair of the Standards Committee, representative from the trades and/or forums, NERC staff, BOT members, and others. Projected milestones would include:

• April 1 - an initial progress report from the steering group to the full MRC

• MRC Informational Webinar – a preview of the presentation intended for the BOT meeting in May

• May meeting – the full presentation and discussion to the BOT

Rules of Procedure (ROP) Updates Rebecca Michael, associate general counsel, NERC, reviewed a number of substantive changes to the ROP that are scheduled to be presented to the board for approval on February 9.

The substantive changes also include a proposal to delete appendices, 3C and 6. There are currently agreements and memoranda of understandings in place between NERC and it international partners that warrant the retirement of the current Appendix 3C. Appendix 6 contains minor administrative details that no longer warrant inclusion in the ROP.


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Future action regarding the ROP includes:

• Edits to Appendix 8 following the implementation of the event analysis process document; addressing the roles of situational awareness staffing in the ES-ISAC.

• Section 511, interventions in regional transmission organizations (RTOs)/ independent system operators (ISOs) enforcement matters. Action on this section was deferred to the BOT meeting on February 23, 2012.

The following comments were provided by the MRC members regarding this topic:

• The board is asked to delay their decision/approval of the proposed updates and deletions to the ROP in an effort to give the MRC and Industry ample time to review and provide final inputs to the changes discussed today.

• Some are concerned about changes to Section 400 that grant an appeals process to the Regional Entity (RE) if a ruling from the hearing body is not considered favorable or desirable. Is there an added concern for circumstances involving REs that select/appoint the hearing body?

• Some are in support of the RE acquiring the ability to appeal the decision of the hearing body. This change to the ROP is considered a positive parallel to the existing language that currently limits appeals to the RE.

• There is large support for the removal of Appendix 8 from this cycle of changes to the ROP. Future changes to Appendix 8 should be presented to the MRC as a package submission, in conjunction with other applicable areas of the ROP.

• It is unclear what warrants the MRC’s discussion or policy input regarding changes to NERC’s bylaws. A stakeholder would have to garner support from 50 entities across two segments or acquire a NERC officer to champion their proposal for a change to NERC’s bylaws.

• The proposed change to the certification of entities is not a minor change. A reliability business case is needed for this proposed change to determine the impact across Industry and the benefit to reliability.

Events Analysis Update and Reliability Risk Trends Earl Shockley, director of reliability risk management, NERC, summarized the events analysis field trial that resulted in the finalization of an ERO event analysis process document scheduled to be presented to the board for approval on February 9. The following comments were provided by the MRC members regarding this topic:

• Members would like to receive additional details regarding the industry alert expected to be issued for the purpose of identifying change management events.


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• There is little known about the timeframes that are targeted by NERC to issue reports from event analysis and lessons learned. How will the industry know when to expect these reports to be issued and available for peer-reference and use?

NERC confirmed it will ensure there is no breach in confidentiality, for those entities or regions involved in the event analysis process, through the release of these lessons learned and reports (Exhibit F). Generator Owners and Operators That Own and Operate Transmission Facilities Mike Moon, director of compliance, NERC, presented an update on the status of draft compliance guidance and directive concerning the registration of Generator Owner/Operators (GO/GOPs) as Transmission Owner/Operators (TO/TOPs). The following comments were provided by the MRC members regarding this topic:

• It is important to support the work invested by the SDT and recognize the potential for benefit to the industry. There is continued encouragement to utilize the SDT, NERC staff, the regions, etc. and standards development process that is currently in place to address any concerns that may arise around this issue.

• The full package of 4 standards (FAC-001, FAC-003, PRC-004 and PRC-005) might be remanded to the SDT to allow time to resolve the issue and objection of on FAC-003 and return for MRC input during the May meeting. PRC-005 will also be balloted before the May meeting.

• There may be some facilities that are so complex that they require additional standards to be applied. A one size fits all approach may not be sufficient for this issue.

• The SDT and NERC staffs need to ensure all gaps are addressed with this set of standards before the package is submitted to FERC.

• Is there a list of requirements that are still a concern for NERC staff? Based on the presentation from the SOTC, it is not clear which standards NERC staff believes should be within scope of this current project.

• Complexities surrounding issues, such as this one, ultimately limit the timeliness involved with the standards development process.

NERC staff agreed to provide a review of the technical details that can support the SDT and provide a full picture regarding “completeness” of this initiative.


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COM-002 Interpretation The MRC provided the following input on the interpretation from SDT on COM-002 regarding three-part communications during emergency circumstances:

• The interpretation of the COM-002 standard is the industry’s opinion via the SDT.

• Nothing in the standard prevents using three-part communications during normal, non-emergency conditions and there is no penalty described in standard for using three part communications during non-emergency conditions.

• A concern was raised that the standard interpretation appears that we are backing away from reliability. Also, what is the risk between now and when the standard interpretation is approved?

• If three-part communications is used on a routine basis, can we determine when the emergency actually occurred?

• Three-part communications will not necessarily solve all dilemmas surrounding the exchange of information between entities. Many entities strive to use three part communications most of the time while clearly recognizing that during emergencies it is required. Pursuing entities in terms of compliance should only be done if there is failure during emergency circumstances. Allocating resources to hunt down every time we fail to use three part communications, even in the routine operations, then we are not focusing ourselves on the risks that are most important.

• Industry has been surprised with how the standard has been enforced, based on how we want it to read or say and not by what it actually does read/say.

• The enforcement issue implies there may need to be a review of the language within the standard itself and not necessarily the interpretation of that standard that we are faced with today.

• It is hard to demonstrate that an entity has participated in three part communications 100% of the time. Is it a violation with a penalty process if one sample is found where three part communications was not used, during non-emergency times? We need to focus on making a reliability difference.

• Is this interpretation following the strict construction-approach of the standard? The MRC concluded that the interpretation does follow the strict intent of the standard, during emergency conditions. The way the standard was being applied ultimately leads to the need for an interpretation.


8

Definition of Adequate Level of Reliability (ALR)* The ALR task force is re-evaluating the existing ALR definition and determining objectives that will be measurable along with cost benefits, load loss distinctions, and an accompanying definition of “cascading”. Ongoing efforts include the development of a white paper on the management of social impacts and risks to reliable BES operations. The schedule for industry comment is March 2012. The MRC requested an update during their May informational session prior to the next face-to-face meeting in Arlington, Virginia. The BOT is expected to receive a final presentation in November 2012.

Bulk Electric System (BES) Definition — Filing of Phase 1 and Preparations for Phase 2 Herb Schrayshuen, vice president of standards and training, NERC, recognized the success of Phase 1 and confirmed the petition was filed with FERC in January 2012. Phase 2 is underway to finalize the SAR, develop the technical justification, and provide clarification from Phase 1. The schedule for industry comment is March 2012. The MRC requested an update during their May informational session prior to the next face-to-face meeting in Arlington, Virginia. Geomagnetic Disturbance Task Force (GMDTF) Update Mark Lauby, vice president of reliability assessment and performance analysis, NERC, provided an update on the GMDTF’s interim report. The major conclusions include loss of reactive power, challenge to maintain supply, and damage to certain transformers. The task force continues to work with industry to develop open source coding, create source tools for modeling, simulation, and measurement, and to review NERC reliability standards for opportunities for enhancement. The BOT is expected to receive the interim report for acceptance and endorsement of the recommendations during the February 23 meeting. An embargoed copy will be shared with various entities following BOT acceptance and endorsement. The following comments were provided by the MRC members regarding this topic:

• This is a positive demonstration on how technical reports should be developed based on accurate data. Industry provided world class experts to support this task force initiative with NERC. This is how NERC is intended to work and operate.

• Members want to ensure this good work and the recommendations are continually shared with FERC, Congress and other entities.

• A parallel communication effort should be established with the Electricity Sub-Sector Coordinating Council (ESCC) regarding the release and socialization of this report.


9

Compliance Enforcement Initiative (CEI) Update Ken Lotterhos, director of enforcement, NERC, confirmed NERC is preparing for the six-month status report to submit to FERC during March 2012 and is seeking comments from industry by February 23. The following comments were provided by the MRC members regarding this topic:

• A question was asked about the difference in timelines between processing the FFT violations versus the full notice of penalty (NOP) violations.

• Many regions initiated the FFT process with a majority of under-processed cases and immediately noticed efficiencies. As more cases enter the FFT process, efficiencies are expected to continue.

• A plan needs to be in place with a schedule for how auditors will accomplish all the steps necessary to reach Phase 2.

• The MRC is interested in knowing how FERC will address FFT. FERC staff acknowledged the MRC’s interest to receive more information once it becomes available. NERC confirmed its intent to provide more data for the FFT and NOP processes so issues such as timelines are clearer to the Industry. Culture of Reliability Excellence Eric Ruskamp, standards and compliance manager, Lincoln Electric System, provided a presentation on the subject matter expertise of its personnel who are cross trained to address NERC standards, compliance, and enforcement (Exhibit G) Tom Bowe, executive director of reliability and compliance, PJM Interconnection, is scheduled to provide a presentation during the May 2012 meeting. November 2011 FERC Technical Conference on Reliability There were no MRC comments regarding this FERC technical conference. May 8, 2012 Meeting and Future Meetings The following are future MRC meeting dates and locations:

• May 8–9, 2012 – Arlington, VA

• August 15–16, 2012 – Quebec City, Canada

• November 6–7, 2012 – New Orleans, LA

• February 6–7, 2013 – San Diego, CA

• May 8–9, 2013 – Philadelphia, PA


10

• August 14–15, 2013 – Montreal, Canada

• November 6–7, 2013 – Atlanta, GA

• February 5–6, 2014 – Phoenix, AZ Update on Regulatory Matters Chair Helyer invited MRC members with questions or concerns regarding additional regulatory matters to meet with David Cook, senior vice president and general counsel, NERC at the conclusion of the meeting. Adjournment There being no further business, the meeting terminated at 5:30p.m. MT. Submitted by,

Holly Mann Secretary

Agenda Item 2 MRC Meeting

August 15, 2012

Future Meetings

Action None Background Below are the future meetings as approved by the board on May 11, 2011. Remaining 2012 Date November 6–7 New Orleans, LA 2013 Dates February 6–7 San Diego, CA May 8–9 Philadelphia, PA August 14–15 Montreal, Canada November 6–7 Atlanta, GA 2014 Dates February 5–6 Phoenix, AZ

Agenda Item 4.a MRC Meeting August 15, 2012

Member Representatives Committee Officer and Sector Elections

Action None Background Chair Scott Helyer will announce the upcoming election of Member Representatives Committee (MRC) officers and the procedure for MRC nominations for those members whose terms expire in February 2013. The tentative schedule for these elections is shown below. MRC Officer Elections Friday, August 31 – nomination period opens Monday, October 1 – nomination period closes Tuesday, November 6 – election of officers for following year by current MRC members MRC Member Nominations and Elections Monday, September 10 – nomination period opens Tuesday, November 13 – nomination period closes Monday, December 3 – election begins Friday, December 14 – election ends MRC membership terms list and applicable sections of the NERC Bylaws can be found via the following links: MRC Membership Terms Article VIII of the Bylaws (Sections 3, 4 and 5)

http://www.nerc.com/fileUploads/File/Membership/Membership_of_MRC_2012-2014_20120807.pdf�

http://www.nerc.com/files/Bylaws-060707.pdf�

Agenda Item 4.b MRC Meeting August 15, 2012

Update from the Board of Trustees Nominating Committee Action None Background On May 8, 2012, Chair Scott Helyer invited Member Representatives Committee (MRC) members to volunteer to serve on the Board of Trustees Nominating Committee. In response to this solicitation, several members of the MRC expressed interest in serving with MRC Chair and Vice Chair on the Nominating Committee, as listed below:

• Scott Helyer – MRC Chair

• Carol Chinn – MRC Vice Chair

• Sylvain Clermont – Federal/Provincial Sector

• Terry Boston – ISO/RTO Sector

• John A. Anderson – Large End-Use Electricity Customer Sector Board Nominating Committee Chair, Jan Schori, will provide a status report on the planned activities and schedule for the committee.

Agenda Item 6 MRC Meeting August 15, 2012

Standards Process Input Group (SPIG) Recommendations This item contains the following attachments as part of the update on the recommendations of the SPIG, as assigned by the Board of Trustees (Board) at its May 2012 meeting, including several action items: Agenda Item 6a Draft Charter for the RISC and proposed slate of initial RISC members to address Recommendation 2 of the SPIG.

• Exhibit 1 – Draft Charter of the RISC ― Endorse

• Exhibit 2 – Initial Slate of Members to the RISC, to be provided under separate email cover on or about August 13, 2012 ― Endorse

Agenda Item 6b.i Update on the Standards Committee’s activities to implement Recommendations 1, 4, and 5 of the SPIG ― No Action Agenda Item 6b.ii Update on NERC management’s activities to address Recommendation 3 of the SPIG ― No Action

• Exhibit 3 – Draft Annual Reliability Priorities Planning Process

Agenda Item 6a MRC Meeting August 15, 2012

Reliability Issues Steering Committee (RISC) Charter and Initial Slate to the RISC –

Recommendation 2

Action Approve the Reliability Issues Steering Committee (RISC) Charter and initial slate of members. Background On May 9, the Board of Trustees (Board) accepted the SPIG report, endorsed its five recommendations, and tasked the SPIG to develop a charter for the RISC – SPIG Report Recommendation 2. Recommendation 2: Reliability Issues Steering Committee — The NERC Board is encouraged to form a RISC to conduct front-end, high level review of nominated reliability issues and direct the initiation of standards projects or other solutions that will address the reliability issues. Status The draft RISC charter (Exhibit 1) addresses the overall function and responsibilities of the RISC as well as its membership and accountability to the Board. The primary function of the RISC is to address, at a high level, a wide range of potential reliability issues, and to make recommendations on “if” and “how” NERC should address them. As such, the RISC is not solely focused on standards-driven solutions to these issues, but rather on whatever solution or set of solutions best addresses the reliability risks created by these issues. The SPIG recognizes that, in most cases, the Board will direct actions based on the recommendations provided by the RISC; therefore the charter is not intended to prescribe details regarding interaction with the various standing committees. However, in cases where the RISC and a particular standing committee(s) are in full agreement with the recommendation, the Board will be informed and the committee(s) will proceed with its implementation. In July 2012, Member Representatives Committee (MRC) Chair Scott Helyer announced to the MRC the opportunity to nominate candidates for initial membership to the RISC. A nomination procedure was developed to clarify how the initial slate of members would be selected by the SPIG and proposed to the MRC and Board for approval at the August 15 and 16 meetings. A draft RISC charter was developed by the SPIG and distributed to the MRC for comment in mid-June. The SPIG reviewed the comments received and developed the current version, with a slate of 12 proposed members to the RISC (Exhibit 2-to be distributed under separate cover). During the development of the RISC charter, the SPIG tried to address the following:

• Allocation of membership to include stakeholder and committee-based participation and support from NERC senior staff;

• A broad range of industry and stakeholder input and support;

• A function for the analysis of performance gaps, technical viability, reliability benefit, cost impact/justification, clarity of scope, etc.;

• A process for recommending to the board any key initiatives and priorities regarding Electric Reliability Organization (ERO) strategic priorities, standards projects, and/or alternate solutions; and

• Milestones and timelines for standards projects and alternate solutions. If MRC members or NERC Board members have questions or need additional information, they may contact Scott Helyer, chair of the MRC and SPIG, at [email protected] or Holly Mann, MRC secretary and associate director of member and regional relations, at [email protected].

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Agenda Item 6b.i MRC Meeting August 15, 2012

Standards Committee Report - Recommendations 1, 4, and 5

Action None Background This report provides highlights of the Standards Committee’s (SC) activities to implement Recommendations 1, 4, and 5 of the SPIG. Recommendation 1: NERC should continue to meet the minimum requirements of the American National Standards Institute (ANSI) process to preserve ANSI accreditation. Status A draft set of proposed revisions to the Standard Processes Manual (SPM) was developed by the SC and Standards Committee Process Subcommittee (SCPS) and posted for stakeholder comment in mid-June. The SC plans to review stakeholder comments and post a second draft of the revisions to the SPM in August. During the development of the proposed revisions, the SC scrutinized each of the proposed revisions against ANSI Essential Requirements and, in several cases when clarification was needed to ensure that the proposed revisions were consistent with maintaining ANSI accreditation, asked NERC staff to consult with ANSI. Recommendation 4: The Board of Trustees (Board) is encouraged to require that the standards development process address the following four sub-parts to Recommendation 4:

• 4.1 – The use of Results-Based Standards (RBS);

• 4.2 – Cost effectiveness of standards and standards development;

• 4.3 – Alignment of standards requirements/measures with Reliability Standards Audit Worksheets (RSAWs); and • 4.4 – The retirement of standards that are no longer needed to meet an adequate level of reliability.

Status • 4.1 – Use of Results-Based Standards (RBS). No change to the standards process is

required to encourage the use of a results-based approach to drafting standards. However, one process revision included in the draft revisions posted for stakeholder

comment would force drafting teams to think about the results-based model by assigning a results-based category to each requirement. Although the proposal is in a rough draft stage and needs further refinement to ensure that the needs of all stakeholders, including Electric Reliability Organization (ERO) compliance enforcement staff, are met with the new approach. The purpose of assigning a results-based category to each requirement is to assist in assigning a starting point for determining sanctions in the case of a violation, and has the added benefit of ensuring that drafting teams are considering the results-based model.

• 4.2 – Cost effectiveness of standards and standards development. The SC posted for stakeholder comment a proposed guideline for an approach to considering cost at two stages of the standards process: 1) prior to initiating development of a standard, and 2) after a drafting team has developed draft requirements. A group of volunteers from the SCPS plans to review stakeholder comments and revise the guideline so that it can be posted for a second time; concurrent with the second posting of revisions to the SPM. The SC plans to pilot the process in the guideline during the second half of 2012 in order to gain experience in gathering stakeholder input on cost effectiveness.

• 4.3 – Alignment of standards requirements/measures with Reliability Standards Audit Worksheets (RSAWs). The SC is working with ERO compliance staff to develop procedures for developing RSAWs in parallel with standards development. The SC has identified two standards, PRC-027 and COM-003, as candidates for development and posting of an RSAW in parallel with the development of the standard, with technical input from the standard drafting team.

In addition, the proposed revisions to the SPM, if supported by stakeholders, adopted by the Board, and approved by regulators, would move the compliance information that is currently housed in a standard, including measures, into the RSAW and would replace certain compliance elements (Violation Risk Factors (VRFs) and Violation Severity Levels (VSLs)) with a much-streamlined reference to a results-based requirement category. This streamlining of the standard, combined with enhanced RSAWs developed and posted in parallel with the standard, is intended to increase the clarity of the reliability objectives of the standard as well as compliance obligations.

• 4.4 – The retirement of standards that are no longer needed to meet an adequate level of reliability. The SC, at its July 2012 meeting, moved forward with a project to address retirement of requirements that do not contribute to reliability by authorizing the posting of a draft Standards Authorization Request (SAR) that proposes an initial set of such requirements, and appointing a drafting team to respond to stakeholder comments on the SAR. The initial set of requirements proposed for retirement is intended to be limited to those requirements where retirement will be non-controversial. A subsequent phase of the project is planned to address standards and/or requirements that require further study to determine whether they are necessary to meet an adequate level of reliability.

Recommendation 5: The Board is encouraged to require the standards development process be revised to improve timely stakeholder consensus in support of new or revised reliability

standards. The Board is also encouraged to require standard development resources to achieve and address:

• Formal and consistent project management; and

• Efficient formation and composition of SDTs. Status The proposed revisions to the SPM include a number of changes intended to facilitate the timely development of stakeholder consensus while making efficient use of drafting team resources. The proposed revisions would streamline the commenting and balloting process by eliminating the initial formal comment period in favor of enhanced informal outreach to develop early support for an approach before the drafting team begins formally posting its work. Under the proposed revisions, a drafting team would not be required to respond to comments until a standard was a “final draft.” In order to ensure that stakeholders who ballot standards are accountable for assisting drafting teams in developing a consensus standard, the proposed revisions would essentially require that balloters casting a negative ballot provide a reason for their dissent. Other elements of Recommendation 5 can be implemented without revisions to the SPM. For example, the SC has been working with NERC staff to implement a formal and consistent approach to managing standards development projects. In addition, the SC has recognized the value of forming drafting teams that include a variety of skill sets to supplement the requisite technical expertise. Since the Board approved the SPIG recommendations, the SC has appointed only one drafting team, for the Paragraph 81 project. Consistent with the SPIG recommendations, this team includes members with facilitation, legal, compliance, and project management expertise in addition to technical experts. If MRC members or NERC Board members have questions or need additional information, they may contact Allen Mosher, chair of the Standards Committee, at [email protected] or Herb Schrayshuen, vice president and director of standards and training, at [email protected].


Agenda Item 6b.ii MRC Meeting August 15, 2012

Management Report – Recommendation 3

Action None Background NERC management was assigned to address SPIG Recommendation 3. Recommendation 3: The Board of Trustees (Board) is encouraged to task NERC management, working with a broad array of Electric Reliability Organization (ERO) resources (e.g., MRC, technical committees, Regional Entities, trade associations, etc.) to develop a strategy for improving the communication and awareness of effective reliability risk controls which increases input and alignment with state, federal, and provincial authorities.

• 3.1 – Interface with governmental authorities to align priorities and timing of reliability initiatives. Establish and align priorities early on during the nomination of the reliability issue

• 3.2 – Develop methods to effectively communicate progress and manage expectations

• 3.3 – Promote effective rules of engagement of state, federal, and provincial regulatory staff in accordance with jurisdictional requirements

• 3.4 – Following successful ballot of standard and approval by the Board, pre-filing meetings will be held with FERC staff and individual Commissioners to help ensure FERC approval without conditions; similar efforts will apply with governmental authorities in Canada

• 3.5 – Responsibility for managing the details above, concerning progress and expectations

• 3.6 – Encourage regulatory authorities to permit staff to submit written comments to the drafting team during informal and formal comment periods

Status The key objective of this recommendation is to gain regulatory support for the ERO, its priorities and reliability risk mitigation initiatives. As a general matter, the final disposition of Recommendations 1, 4 and 5 will determine the outreach and communication effort needed. A number of the initiatives called for are underway. The thrust of this recommendation is to gain regulatory support in Canada and the U.S. for the strategic direction of NERC.

The specific actions include:

• A1 – Strategic planning outreach with the Canadian Provincial Regulators and thought leaders. Linked to SPIG recommendations 3.1, 3.2 and 3.3.

• A2 – Strategic planning outreach with the U.S. Federal Regulator. Linked to SPIG recommendation 3.1, 3.2 and 3.3.

• A3 – Expand outreach to the Trades and other industry groups. Linked to SPIG recommendation 3.2.

• A4 – Development of an annual open industry and regulator conference, scheduled to provide timely input and influence for the ERO budget preparation. Linked to SPIG recommendation 3.1.

• A5 – Accountability has been assigned to Janet Sena and Charlie Berardesco. Linked to SPIG recommendation 3.5.

• A6 – NERC Legal Department has taken initial steps with the U.S. Federal Regulator to obtain support for obtaining regulatory input, in writing, to the standards development process. Linked to SPIG recommendation 3.6.

Enclosed is a draft annual reliability priorities planning process, which proposes a timeline and process for engaging a wide array of input and alignment for planning, communicating, and managing reliability priorities and risk controls among policymakers, industry and other stakeholders (Exhibit 3). If MRC members or NERC Board members have questions or need additional information, they may contact Janet Sena, vice president and director of policy and external affairs at [email protected].


Reliability Issues Steering Committee Charter July 21, 2012

Purpose

The Reliability Issues Steering Committee (RISC) is an advisory committee that reports directly to the NERC Board of Trustees (the Board) and triages and provides front-end, high-level leadership and accountability for nominated issues of strategic importance to bulk power system (BPS) reliability. The RISC assists the Board, NERC standing committees, NERC staff, regulators, Regional Entities, and industry stakeholders in establishing a common understanding of the scope, priority, and goals for the development of solutions to address these issues. In doing so, the RISC provides a framework for steering, developing, formalizing, and organizing recommendations to help NERC and the industry effectively focus their resources on the critical issues needed to best improve the reliability of the BPS. Benefits of the RISC include improved efficiency of the NERC standards program. In some cases, that includes recommending reliability solutions other than the development of new or revised standards and offering high-level stakeholder leadership engagement and input on issues that enter the standards process. Overview and Functions

1. The RISC is responsible for evaluating reliability issues and risks identified by stakeholders, regulators, and the Board that are within the scope and jurisdiction of the Electric Reliability Organization (ERO). In general, it is expected that a reliability issue or risk is:

a. Based on previous documentation;

b. Not sufficiently covered by a current reliability standard to mitigate the reliability issue or risk; or

c. Linked to actual events that provide an example of the reliability issue or risk.

2. In order for the RISC to reasonably and efficiently perform its function, RISC will request that any person or entity identifying a reliability issue or risk provide the following information when a reliability issue or risk is identified for consideration:

a. Information to provide a technical understanding/description of the reliability issue or risk;

b. Studies, analyses, and data necessary to support the development of a standard or other action (lessons learned, alert, technical paper, etc.);

c. Recommended reliability performance results required/expected by the standard or other action;

d. Suggestions for how reliability performance would be evaluated; and

e. A justification or proposal for assessing reliability benefits and cost impacts.

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Exhibit 1

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Reliability Issues Steering Committee Charter 2

3. The RISC shall triage and evaluate reliability issues and risks by:

a. Seeking assistance and requesting that additional work be performed by the standing committees or the Member Representatives Committee (MRC), if that is the consensus of the RISC members, or requesting the Board to assign that work to the appropriate standing committee. If requested by the RISC, standing committees shall provide a work product back to the RISC that assists the RISC in making a comprehensive and informed recommendation.

b. Requesting the Board to provide additional non-NERC resources and expertise, as needed, to assist with the development of recommendations, risk project assignments, and follow-up assessments to the Board.

c. Encouraging open dialogue and sharing of information among the Board, NERC standing committees, the MRC, NERC staff, regulators, Regional Entities, and industry stakeholders needed to recommend project timelines necessary to accomplish an achievable solution.

d. Considering findings from recent system events, lessons learned, and outcomes of risk trends and indices.

e. Requesting additional information from the nominee, if necessary.

4. Upon the completion of its triage and evaluation of each reliability issue and risk, the RISC:

a. Reports its findings to the Board, NERC Management, and affected standing committees and recommends:

i. A NERC program, committee, or other entity to undertake a specific action that could include, but not be limited to, the development of reliability standards, guidelines, bulletins, lessons learned, or other technical documents;

ii. The reliability issue be tabled until more information is provided for necessary clarification; or

iii. No new or additional action is taken.

b. Develops and submits a Reliability Risk Statement to accompany recommendations for specific actions that includes a full description of the risk issue, including the urgency and priority of recommended remedial measures and other initiatives/activities recommended by the RISC, and a preliminary assessment of the costs and benefits associated with the risk issue and proposed remedial measures.

c. Identifies any recommendations that are contingent upon changes to NERC policies or material changes to the NERC business plan that must be approved by the Board prior to implementation.

d. Reinforces that any recommendation of the RISC can be appealed first to the RISC and then to the Board.


5. The RISC also:

a. Responds to the Board’s decision to accept, reject, or remand the recommendation for further clarification.

b. Updates the Board no less than quarterly and at such other times as deemed necessary by the RISC chair, or as requested by the NERC Board chair.

c. Prepares recommendations to the Board on the relative priority and resources that should be allocated to various emerging and continuing reliability risk issues of strategic importance to BPS reliability.

d. Performs such other functions that may, from time to time, be delegated or assigned by the Board.

e. Monitors the execution of any recommendations and provides the Board with updates on the progress of such recommendations.

f. Reviews and provides recommendations to the Board, NERC Staff, and Standards Committee of any SAR, interpretation request, guideline, CAN, RSAW, standard, or other technical document nominated for review by the RISC. The RISC’s review of such items can include the priority, scope, cost benefit, and content.

g. Reviews and provides recommendations to the Board, NERC Staff, and the various standing committees regarding reliability risk issues and their priorities as necessary for the ERO to establish a three-year plan to improve the reliability of the BPS.

Membership

6. The RISC shall be comprised of no less than 12 members, typically of the following allocation:

a. Six (6) stakeholder-based― four (4) from the MRC and at least two (2) at-large members (not members of the MRC);

b. Five (5) committee-based―one (1) from each of the standing committees: Standards (SC), Operating (OC), Planning (PC), Critical Infrastructure Protection (CIPC), and Compliance and Certification (CCC). These members will be the chair or vice chair unless otherwise recommended by the standing committee and be subject to NERC Board approval; and

c. One (1) NERC Staff―senior NERC staff recommended by the NERC CEO as a non-voting member.

7. In advance of their annual May meetings, the NERC Board and the MRC will form a nominating committee to solicit a pool of candidates who meet the following general criteria:

a. Geographic and International diversity, including international, such that Eastern, Western, and Texas Interconnections, along with Canada are represented on the RISC;

b. Sector, size, and asset (transmission, distribution, load, generation, etc.) diversity;

c. High-level understanding and perspective on reliability risks;


d. Experience in a leadership role or background in an executive-level position is strongly preferred; and

e. Balanced consideration of these criteria, across the entire membership of the RISC.

8. At its May meeting each year, the MRC shall review and recommend to the Board a slate of stakeholder-based members to the RISC. The Board will be responsible for appointing the committee-based members to the RISC. All RISC members will be appointed by the Board to serve for two-year terms, where half of the terms will be staggered.

9. The Board shall appoint a chair of the RISC (from the member slate and as provided above) to serve a two-year term and direct the activities of the RISC, and work toward reaching consensus on all recommendations and actions.

Meetings

10. The RISC meets based on the frequency and rate that reliability issue nominations are received. Meetings shall occur at least once every quarter and can be in person or by conference call as determined by the chair. All meetings of the RISC will be open (except as noted in the paragraph below for confidential sessions). Confidential Sessions. The chair of the RISC may limit attendance at a meeting or portion of a meeting, based on confidentiality of the information to be disclosed at the meeting. Such limitations will be applied sparingly and on a nondiscriminatory basis as needed to protect critical energy infrastructure information and other information that is sensitive to one or more parties. Confidentiality agreements may also be applied as necessary to protect sensitive information.

Charter Review

11. At the first anniversary of the RISC formation and every third year thereafter, a review of the RISC Charter shall be performed by the MRC to determine whether any changes are needed to the RISC Charter. Any changes identified by the MRC would be presented to the NERC Board for approval.

Annual Reliability Priorities Planning Process Draft

Background The Standards Process Input Group (SPIG) issued policy recommendations intended to improve the priority, product, and process for developing NERC Reliability Standards and offer alternate solutions to address identified risks to the Bulk Power System (BPS). In an effort to better understand, articulate and incorporate, into the standards development process, the appropriate accountabilities, one of the group’s recommendations identified the need to specifically outline NERC reliability priorities with state, federal, and provincial regulators. The following proposal is suggested to the Board of Trustees (the Board) for consideration and endorsement for planning, communicating, and managing reliability priorities and risk controls among policymakers, industry and other stakeholders. SPIG Recommendation Interface with Regulatory and Governmental Authorities - The Board is encouraged to task NERC management, working with a broad array of ERO resources (e.g., MRC, technical committees, Regional Entities, trade associations, etc.) to develop a strategy for improving the communication and awareness of effective reliability risk controls which increases input and alignment with state, federal, and provincial authorities. NERC Management Proposal NERC management recognizes there are opportunities, existing and new, to improve the communication and awareness of reliability priorities and risk controls by engaging policymakers who have interest in the outcome of Reliability Standards or other solutions. Obtaining input on the ERO risk priorities and controls can be achieved through increased communication of reliability objectives, an understanding of the benefit(s) to be gained from a standard or alternate solution and awareness of federal, provincial and state policymakers’ issues and concerns related to reliability of the bulk power system. The following timeline and process are proposed for engaging a wide array of input and alignment for the development of priorities and vetting of reliability issues. Third Quarter (July – September 2012)

• Seek MRC discussion and Board endorsement of the Annual Reliability Priorities Planning Process to engage state, federal and provincial authorities in developing reliability priorities and risk controls to the BPS.

• Initiate meetings with the appropriate policymakers, FERC Commissioners and Canadian authorities, to receive input on reliability priorities and risk control process in accordance with jurisdictional requirements

Exhibit 3

Annual Reliability Priorities Process - DRAFT 2

• Identify specific reliability priorities and risk controls policymakers would like to see or not see addressed for 2013. This information will be used as input into the Annual Reliability Technical Roundtable.

Fourth Quarter (October – December 2012)

• NERC management will conduct a Reliability Technical Roundtable, to engage industry and stakeholders, FERC and other policymakers to further identify and discuss 2013 reliability priorities and risk controls.

• NERC will conduct follow-on meetings with the Regional Entities staff, standing committees, the Reliability Issues Steering Committee (RISC), etc. to increase awareness and familiarity with the select priorities and risk control initiatives/activities for 2013.

First Quarter (January – March 2013) • NERC and FERC staffs engage in meetings to reaffirm the 2013 priorities and timing of reliability

initiatives/activities anticipated for the year.

• NERC will communicate 2013 priorities to Canadian regulators through CAMPUT, trilateral and meetings with Canadian industry and policymakers

• NERC management will communicate 2013 priorities to industry trade association CEOs.

• NERC will communicate 2013 priorities to policy decision makers and other attendees at Reliability Technical Roundtable.

• Seek Board approval of the final Annual Reliability Priorities Planning Process.

Second Quarter (April – June 2013)

• NERC completes an annual capstone report that accompanies the State of Reliability Report and reflects the status of accomplishments, to-date, for priorities and risk controls activities.

• As progress on priorities and risk initiatives occur, pre-filing meetings will be held between NERC and FERC staffs and with individual Commissioners on an as needed basis, to provide information and receive feedback on reliability priority initiatives to facilitate awareness and lay the groundwork for FERC approval without conditions; similar communication efforts will also apply with governmental authorities in Canada.

Third Quarter (July – September 2013)

• Initiate meetings with the appropriate policymakers, to include FERC Commissioners and Canadian authorities, to identify reliability priorities and risks controls for 2014.

• Identify specific reliability priorities and risk controls policymakers would like to see or not see addressed for 2013. This information will be used as input into the Annual Reliability Technical Conference.


Bulk Electric System Definition ― Phase 2 Report

Action None Background In the Bulk Electric System (BES) Phase I project, there was not sufficient technical information immediately available to support resolution of the issues raised by stakeholders in a timely manner. To build a defensible case for adoption for some of the proposals, a significant Phase 2 effort has been initiated to collect information from stakeholders, analyze that information, and develop specific proposals. A progress report on the Phase 2 effort will be presented to the Member Representatives Committee (MRC) at the meeting. If MRC members have questions or need additional information, they may contact Herb Schrayshuen, vice president and director of standards and training at: [email protected].


Agenda Item 7.b MRC Meeting August 15, 2012

Adequate Level of Reliability Task Force Status Report Action None

Background The Adequate Level of Reliability Task Force (ALRTF) met in Washington, DC on June 28, 2012 and by conference call on July 16, 2012 to review the comments it received on its May 25 through June 25, 2012 posting of the Adequate Level of Reliability (ALR) definition, a technical report supporting the definition, a discussion paper on risk tolerance for widespread Bulk Electric System (BES) outages, and a mapping document of the proposed ALR reliability objectives against NERC’s Reliability Principles.

While commenters were generally supportive of the concepts in the definition and the extensive background work prepared by the ALRTF, the Task Force received 130 pages of comments and still has some substantive issues to address. Through mid-August, the ALRTF will be working to address all of the comments and make corresponding adjustments to the ALR definition and supporting documents. The two largest issues that remain to be addressed based on the comments are (1) concerns about the inclusion of adequacy given the Electric Reliability Organization (ERO)’s statutory limitations in Section 215 and (2) how the definition will be used, a topic on which ALRTF leadership has been collaborating with senior NERC staff.

The ALRTF plans to post its revised definition and supporting documents for a 30-day comment period beginning mid-August. Following the comment period, the ALRTF aims to respond to comments and prepare its documents for presentation to the Board of Trustees in November.

Allen Mosher, chair of the ALRTF and chair of the NERC Standards Committee, will present and discuss the status of this initiative.

Agenda Item 7.c MRC Meeting August 15, 2012

Status of Communications Standards

Action None Background In the May Member Representatives Committee (MRC) and Board of Trustees meetings a presentation was provided on the status of various communications initiatives (standards and non-standards). A current progress report on these initiatives will be presented to the MRC at the meeting. If MRC members have questions or need additional information, they may contact Herb Schrayshuen, vice president and director of standards and training at: [email protected].



Entity Impact Evaluation Template

Action None Background This provides a status update for the Entity Impact Evaluation (EIE) Template, formally known as the Entity Assessment. The EIE, which is conducted at the entity level, is one component of the Risk-Based Compliance Monitoring Initiative. As discussed at the April Board of Trustees Compliance Committee (BOTCC) meeting, the Risk-Based Compliance Monitoring Initiative consists of components throughout the process – at the program level, the entity level, and in the enforcement processing level, as follows:

• Program Level

Annual Implementation Plan

Actively Monitored List (AML)

• Entity Level

Entity Assessment – The assessment will, among other objectives, determine the frequency, scope and methods of compliance monitoring for each entity.

Compliance Monitoring – Integration of verification of Internal Controls into the compliance monitoring to determine the due diligence a Compliance Enforcement Authority (CEA) must use (the amount of evidence to review) to obtain reasonable assurance the entity is not non-compliant.

• Enforcement Processing Level

Resolution of non-compliance based on risk ― Compliance Enforcement Initiative (CEI) Phase one and two:

o Find, Fix, Track and Report – Lower Risk Possible Violations (PVs)

o Notice of Penalty (NOP) Summary In 2011 the Electric Reliability Organization (ERO) began developing an EIE Template, but by year-end the timeline for the project was extended to obtain greater industry input. The following activities were conducted:

• Early 2012, the Compliance and Certification Committee (CCC) formed a working group to review the work that has been conducted to date and to draft a template that would include categories and information needed to appropriately scope compliance monitoring.

• During April 2012, NERC conducted eight facilitated focus group meetings which consisted of two focus groups for each of the following functional areas: Balancing

Authority (BA)/Reliability Coordinator (RC), Transmission Owner (TO)/Transmission Operator (TOP), Generator Owner (GO)/Generator Operator (GOP) and Small Entities. The focus groups’ input was provided to the CCC working group for consideration. A total of 68 industry representatives from 64 entities participated in the focus groups.

• In May 2012, working with the semi-final draft version of the CCC working group’s template, NERC and the Regional Entities (REs) met to discuss the questions raised by the focus groups and to begin gathering the REs input.

• NERC and the REs met again in June, following the CCC working group’s completion of their final draft template. Further information provided by the focus groups and added to the draft template by the CCC was discussed.

• NERC and the REs met again in July 2012 to finalize the draft template; which was posted on the NERC website for industry comment with the customary 45-day comment period. Comments will be due in early September and the template finalized.

Agenda Item 8.b MRC Meeting

August 15, 2012

Compliance Enforcement Initiative

Action None

Summary NERC continues to process violations through the streamlined Spreadsheet Notice of Penalty (SNOP) and the Find, Fix, Track and Report (FFT) informational filing. Since the initial Compliance Enforcement Initiative (CEI) filing on September 30, 2011, NERC has made 10 SNOP filings and 10 FFT filings with the Federal Energy Regulatory Commission (FERC).1 The Commission has issued orders of no further review on the SNOP and NOP filings submitted through the end of June.2 The six initial FFT filings were accepted through the March 15 Order on the CEI proposal3 and since then two additional filings, through the end of April, have been accepted by the Commission.4

As described in its May 14 Compliance Filing, NERC is also seeking to expand the application and effectiveness of the FFT process. Thus far, CEA enforcement staff has made all FFT determinations. In the next stage of CEI development, CEA compliance monitoring staff (auditors and investigators) will make recommendations to enforcement staff concerning likely candidates for FFT treatment. NERC anticipates that expanding FFT identification will broaden the range of issues that will be afforded FFT treatment much earlier in the compliance monitoring and enforcement process. NERC and the Regional Entities are continuing to explore opportunities to enhance the CEI processes. Additionally, NERC is developing a process to conduct random surveys each year to gauge program performance, as directed in the March 15, 2012 Order. The March 15 Order requires NERC to file a 12-month status report in March of 2013. NERC is working with the Regional Entities and Trade Associations to collect the information required for the one-year report. The Commission will be evaluating the consistency and application of the FFT initiative and will review the effectiveness of the FFT program with regard to such matters as:

(1) The effect of the program on improving bulk power system reliability;

(2) The effect of the program on addressing NERC’s compliance and enforcement program, including its caseload;

(3) The effect of the program on NERC and the Regional Entities better focusing resources on addressing more serious violations;

(4) How NERC’s evaluation of risk in identifying candidate possible violations for FFT treatment has evolved during the implementation of the FFT initiative, including but not limited to how the Violation Risk Factors (VRFs) have been considered in the evaluation;

1 The eleventh set of filings will be made July 31, 2012. 2 Action on the June 30, 2012 filing is expected by July 31, 2012. 3 On March 15, 2012 the Commission issued an order accepting, with conditions, NERC’s proposal to make informational filings in a “Find, Fix, Track and Report” (FFT) spreadsheet format of lesser-risk, remediated possible violations of Reliability Standards. 4 By Commission Order, a FFT filing is deemed closed sixty days after submittal by NERC unless there is cause for the Commission to open particular remediated issues for review. Action on the May 31, 2012 FFT filing is expected by July 31, 2012.

Agenda Item 8.b MRC Meeting

August 15, 2012

(5) Manners in which the FFT mechanism can be improved based on experience to date;

(6) The results of any audits, spot checks or random samplings that NERC or the Regional Entities may have performed during the year with regard to implementation of the FFT proposal; and

(7) The impact, if any, the implementation of the FFT mechanism has had on the number of self-reports submitted.

In the one-year report, NERC also will report on results of its evaluation of the consistency and application of the FFT initiative. Upon review of this one-year report, the Commission may consider any necessary changes going forward, including expanding the scope and parameters of possible violations to be processed by FFT informational filings.

To date, the CEI has received significant support from the Regional Entities and the industry. NERC anticipates the FFT process will continue to result in a better alignment between compliance and enforcement resources and the attention devoted to matters that pose a more serious risk to the reliability of the bulk power system.

Agenda Item 8.c MRC Meeting August 15, 2012

Find, Fix, Track, and Report Order Paragraph 81

Lower Level Facilitating Requirements

Action None Background In its March 15, 2012 Find, Fix, Track, and Report (FFT) Order, the Federal Energy Regulatory Commission (FERC) provided an opportunity for the Electric Reliability Organization (ERO) to examine its standards and “…remove from the Commission-approved Reliability Standards unnecessary or redundant requirements.” This briefing will report on the initial activities to date. Discussion A collaborative core team including NERC, the Regional Entities and industry, as represented by the Trade Organizations,1

was formed to identify potential requirements to be candidates for retirement. This team developed criteria for determining which requirements were appropriate. Based on the criteria, 79 potential requirements were identified, 11 of which are currently being considered for retirement in current drafting projects. The core team submitted a Standards Authorization Request (SAR), a list of potential candidate requirements for the Initial Phase and a proposed schedule to the Standards Committee (SC) for consideration. The submitted schedule proposed filing a response for the Initial Phase to FERC by the end of 2012.

The core team has proposed that the project be executed in phases, with the Initial Phase (also referred to as Phase I) addressing requirements that clearly meet the criteria and do not require modification or technical research. The SC approved the draft SAR at its July meeting. It has been posted for industry comment along with an insert outlining how each of the potential candidates meets the identified criteria and a spreadsheet containing the potential candidates. The SC held approval for the schedule that was submitted along with the SAR pending comments received on the draft SAR. If trustees have questions or need additional information, they may contact Herb Schrayshuen, vice president of standards and training at: [email protected] or Mike Moon, director compliance operations at: [email protected].

1 Edison Electric Institute, American Public Power Association, National Rural Electric Cooperative Association, Large Public Power Council, Electricity Consumers Resource Council, The Electric Power Supply Association and the Transmission Access Policy Study Group


Agenda Item 8.d MRC Meeting August 15, 2012

NERC Compliance Process Bulletin #2012-001

Applicability of PRC-023-1 for Generator Owners Action None Background Compliance Process Bulletin #2012-001 was issued to clarify whether a Generator Owner (GO) is subject to compliance with Reliability Standard PRC-023-1. NERC received requests for clarification from several registered entities and trade associations regarding the applicability of PRC-023-1 for GOs that are not also registered as Transmission Owners (TOs) or Distribution Providers (DPs) or both. The bulletin was posted as final on June 8, 2012. Summary FERC Order No. 733, which approved PRC-023-1, states that GOs that are not also registered as TOs or DPs or both are not subject to compliance with PRC-023-1. PRC-023-1, Requirements R1 and R2 are subject to compliance for the time period beginning July 1, 2010 and ending June 30, 2012. PRC-023-2 revises the requirements of PRC-023-1 and its enforceable period begins on July 1, 2012. For compliance monitoring and audit purposes, this Compliance Process Bulletin only applies to PRC-023-1 and its applicable time period. GOs are subject to compliance with PRC-023-2, which became enforceable on July 1, 2012. Registered entities should refer to the PRC-023-2 implementation table for further information and timelines. References

1. FERC Order No. 733 (Approving PRC-023-1)

2. FERC Order No. 759 (Approving PRC-023-2) If Member Representatives Committee members have questions or need additional information, they may contact Mike Moon, director compliance operations at: [email protected].


Rules of Procedure Process Improvements

Action None Background During 2011, NERC developed and posted for comment numerous proposed revisions to its Rules of Procedure (ROP). As the result of this effort, the Board of Trustees (Board) approved a set of revisions to the ROP on March 14, 2012, and the proposed revisions were filed with FERC for approval on May 7, 2012. During the process of obtaining stakeholder comment on the proposed ROP revisions, NERC received a large number of comments concerning the processes by which the proposed revisions were developed, posted for comment, and approved. The Board will be asked to approve a report that summarizes NERC staff’s review of the processes for developing, obtaining stakeholder input on, and obtaining Board approval for revisions to the ROP. The report is available as part of the August 16 Board agenda package and contains a list of changes and enhancements to these processes which NERC staff recommends should be implemented for future ROP revisions. The report and recommendations will be summarized during the Member Representatives Committee meeting on August 15, and NERC staff will seek Board approval on August 16.


Follow-Up Activities from the 2011 Southwest Outage

Action None

Background Melanie Frye, vice president, planning and operations, WECC, and Dave Nevius, senior vice president, NERC, who is NERC's point person on the FERC/NERC Inquiry report and follow-up activities, will brief the Member Representatives Committee on the status of activities both in WECC and the other Regional Entities. Attachmeƴt 1 – high-level summary, as of July 23, 2012, of the status of Regional Entity (RE) reviews and follow-up activities related to the September 8, 2011 outage recommendations, as requested in a June 5, 2012 letter to the RE executives. Attachment 2 – preliminary summary and analysis of the survey results WECC has received to date, including identified gaps and best practices. Attachment 3 – NERC July 26 letter to WECC requesting detailed report outlining near-term remediation actions completed or in progress to date, and plans for additional actions going forward.

Status of Regional Entity Reviews and Follow-Up Activities Related to September 8,

2011 Outage Recommendations (as of July 23, 2012)

On June 5, 2012, NERC requested that each Regional Entity provide a status report on the actions by its Registered Entities, technical committees, or other work groups within their respective footprints to address the applicable findings and recommendations from the FERC/NERC Inquiry report. In addition to this general request to all the Regional Entities, NERC is working closely and directly with WECC to track progress in addressing the specific recommendations applicable to the WECC RE, WECC RC, and various WECC Registered Entities, and providing weekly updates to FERC OGC representatives. For the remaining seven Regional Entities, the first phase responses focused on those issues from the Inquiry report that were judged to be particularly relevant to reliable operations during the upcoming summer season, with emphasis on the report recommendations in the following areas:

• Next-Day Planning Responsibilities (Recommendations 1-4) • Situational Awareness and RTCA Capabilities (Recommendations 11-16) • Treatment of Sub-100 kV Facilities (Recommendation 17) • Identification and Recognition of IROLs (Recommendation 18) • Review, Analysis, and Coordination of Protection Systems, including RAS, SPS, Safety Nets, etc.

(Recommendations 19-26) • Angular Separation and Line Reclosing Capabilities (Recommendation 27)

The following general observations can be made based on the initial, “first cut” responses from the Regional Entities on these issues:

• All Regional Entities, including WECC, are fully committed to thoroughly reviewing and responding to all applicable findings and recommendations in the Inquiry report, and see this as a unique opportunity to improve reliability operations throughout their respective footprints.

• Regional Entities are taking various approaches to the request and have launched surveys and/or engaged their respective reliability committees to review the applicable recommendations and respond to the specific questions listed in the June 5 request.

• Many of the issues involved in the September 8, 2011 event were unique to WECC and its Registered Entities and do not appear, at least at this juncture, to represent reliability gaps or concerns in other Regional Entities.

July 23, 2012

• At this point, based on the preliminary feedback from the other seven Regional Entities, there is reasonable assurance that no major gaps exist with respect to the Inquiry report recommendations for summer 2012.

• The NERC Planning and Operating Committees are also engaged in reviewing the Inquiry report’s findings and recommendations from a broader North American perspective and may initiate further follow-on activities, the results of which will be incorporated into a final NERC report.

• A more complete assessment of reliability gaps and actions taken by WECC as well as the other Regional Entities will be provided in early September 2012 after the Regional Entities and NERC complete their respective reviews.

Following are some examples to each of these issues based on the preliminary responses from Regional Entities:

Next-Day Planning Responsibilities (Recommendations 1-4)

• Current processes for performing, sharing, and coordinating next-day studies, facility outages, load forecasts, scheduled transactions, and other pertinent system conditions, both within and among RCs, are judged adequate.

• These processes are being reviewed for opportunities to further enhance their effectiveness in areas such as contingency list development, methodologies for identifying sub-100 kV facilities for inclusion in next-day studies and evaluating their impacts, and the determination of trigger points for updates prior to current day operations.

Situational Awareness and RTCA Capabilities (Recommendations 11-16)

• Generally good visibility and situational awareness of own and neighboring systems both at the TOP and RC level; registered entities being asked to review current situation for possible improvements.

• In cases where TOPs lack full visibility and situational awareness, they rely on their RC for this coverage.

• Many entities have already incorporated at least some of the recommendations of the RTTBPTF; entities are revisiting these recommendations in light of the SW outage recommendations to identify further opportunities to enhance SA and RTCA tools.

• Additional attention being given to ensuring consistency between planning and operating models, including the periodicity on which model comparisons should be made.

• Post-contingency mitigation measures, where they are used, will be reevaluated as to their performance during abnormal system conditions.

July 23, 2012

Treatment of Sub-100 kV Facilities (Recommendation 17)

• All Regions include representation of sub-100 kV facilities in their system models, and study the effects of these facilities on BPS reliability as well as the effects of BPS conditions on these sub-100 kV facilities.

• September 8 event has inspired additional review of methodologies for identifying facilities that should be monitoring in RTCA.

Identification and Recognition of IROLs (Recommendation 18)

• Each RC has established procedures for identifying and communicating IROLs to entities within its footprint as well as with neighboring RCs.

• Communication and coordination procedures are regularly reviewed, especially to ensure that generation and transmission facilities and protection systems that can impact BPS reliability are taken into account.

• RCs post their IROL identification methodologies as well as lists of pre-defined IROLs in their respective reliability coordination manuals and procedures.

Review, Analysis, and Coordination of Protection Systems, including RAS, SPS, Safety Nets, etc. (Recommendations 19-26)

• Procedures for coordination and sharing of protection system information are being reviewed to ensure they are sufficient in light of the issues identified in the Inquiry report.

• Particular attention being given to review of RAS/SPS operations and interactions, especially during abnormal or extreme system conditions, their inclusion in operator training, and their periodicity of review.

• Additional attention will be focused on the performance of generators during severe or unusual system conditions, especially the behavior of turbine control systems.

Angular Separation and Line Reclosing Capabilities (Recommendation 27)

• Some RC and TOP RTCA systems have the ability to flag contingencies that would result in standing angles that may exceed synch-check relay limits.

• Additional capabilities are being developed, including a new synchro-phasor monitoring project, that will include monitoring of standing angle differences and streaming data directly into SCADA/EMS systems that will facilitate line reclosing following outages.

W E S T E R N E L E C T R I C I T Y C O O R D I N A T I N G C O U N C I L • W W W . W E C C . B I Z 1 5 5 N O R T H 4 0 0 W E S T • S U I T E 2 0 0 • S A L T L A K E C I T Y • U T A H • 8 4 1 0 3 - 1 1 1 4 • P H 8 0 1 . 5 8 2 . 0 3 5 3

White Paper High Level Summary of September 8, 2011 Pacific Southwest Outage Survey Results

By

Western Electricity Coordinating Council Staff

July 20, 2012

July 20, 2012 3


Background On May 1, 2012, the North American Electric Reliability Corporation (NERC) and the Federal Energy Regulatory Commission (FERC) released their report on the Arizona-Southern California Outages on September 8, 2011 (Report).This joint Report identified 27 findings and recommendations relating to situation awareness; next-day, seasonal, and long-term planning; impact of sub-100-kV facilities; and Interconnection Reliability Operating Limits. Many of these recommendations affect not only the entities that were involved in the event, but extend to all registered entities across the continent.

On June 5, 2012, subsequent to the publication of the Report, WECC received a letter from David Nevius, Senior Vice President of NERC, asking follow-up questions associated with the 27 recommendations from the Report. Using these questions as a basis, on June 11, 2012 WECC issued a survey to Transmission Operators (TOP), Planning Coordinators (PC), Transmission Planners (TP), Generator Owners (GO), and Generator Operators (GOP) to assess the overall practices of entities in the Western Interconnection and identify any reliability gaps and best practices.

This white paper provides a high-level summary of the survey results received to date.1

General Response The survey was sent to 271 entities, including 54 TOPs, 251 GO/GOPs, 45 TP/PCs, and 1 RC.2 WECC has received survey responses as follows:

• TOPS ........... 42 of 54 (78 percent); • GO/GOPs .... 123 of 251 (49 percent); • TP/PCs ........ 30 of 45 (67 percent); and • RC ............... 1 of 1 RC (100 percent).

Although the deadline has passed and the results have been aggregated, WECC encourages all remaining entities to complete the survey and will follow up with the entities that have not responded. It is in the best interest of reliability for WECC to have a full view of practices and processes across the Western Interconnection.

1 Surveys were requested by July 2, 2012.

2 Note: several entities are registered for multiple functions.

http://www.nerc.com/fileUploads/File/News/AZOutage_Report_01MAY12.pdf

http://www.nerc.com/fileUploads/File/News/AZOutage_Report_01MAY12.pdf

http://www.wecc.biz/Lists/SWEvent/NewForm.aspx?Source=http%3A%2F%2Fwww%2Ewecc%2Ebiz%2FLists%2FSWEvent%2Fsummary%2Easpx

July 20, 2012 4


Next-Day Studies The Report included four recommendations on next-day studies and the survey included four questions related to those recommendations.

Summary of Responses Of the TOPs that responded, 84 percent indicated that they perform next-day studies, while the remainder do not. Some of the entities that do not perform next-day studies indicated that they rely on other entities to perform these studies, though it is unclear from the responses whether the other entities are aware of this practice.

Most TOPs indicated that they model known outages and system conditions of their own system. However, many TOPs did not directly respond to the question about whether their next-day studies include the outages and system conditions of their neighbors. Of those that did respond, several indicated that they do not model the transmission or generation outages or the system conditions of their neighbors. Many do include major transmission outages of their neighbors, but not generation outages or load conditions. A few entities do include both transmission outages and generation outages, as well as load conditions of their neighbors.

Of those TOPs that perform next-day studies, only 34 percent share the results of these studies with their neighbors. A large percentage indicated some level of sharing of outage data including the use of the Coordinated Outage System (COS) and Reliability Coordinator (RC) daily calls; but few have formal agreements.

Only 50 percent of responding TOPs indicated that they have studied sub-100-kV facilities to determine whether they could have an adverse impact on reliability and should be included in next-day studies. Another 42 percent indicated that this question was not applicable to them.

Identified Gaps • A significant portion of TOPs do not currently perform next-day studies. This is a

concern because these TOPs do not have a clear view of system conditions for the next day to determine their own operating plans. It is also not always clear that when TOPs rely on other entities to perform studies, that the other entities are aware of this practice.

• Many TOPs do not include system conditions and outages of their neighbors in their next-day studies. This was identified as one of the coordination issues that contributed to the outage on September 8, 2011. Due to the interconnected nature of the Bulk Electric System, it is important for entities to consider the effect to their system of major outages external to their system.

July 20, 2012 5


• Many TOPs have not studied the effect of sub-100-kV facilities, and do not intend to because they believe it is not applicable to them. A sub-100-kV system was identified as contributing to the outage on September 8, 2011. Without studying the effect of sub-100-kV facilities, it is unclear how entities have determined that their systems cannot have an adverse effect.

Best Practices • Entities whose next-day studies include system conditions external to their

system have better situational awareness as they enter the operating day.

• In order to model external conditions, it is necessary for entities to share data. One entity reported having an outage coordination group with neighbors. Others indicated participating in RC daily calls with neighbors where outages are discussed.

• On July 16, 2012, the WECC RC began sharing next-day study inputs and results with those entities that have signed the WECC Synchrophasor and Operating Reliability Data Sharing Agreement (also known as the Universal Non-Disclosure Agreement). All entities are encouraged to sign the Universal Non-Disclosure Agreement and incorporate the RC study inputs in their own next-day studies.

Seasonal Planning The Report included four recommendations on Seasonal Planning, and the survey included seven questions related to those recommendations.

Summary of Responses All but three respondents indicated that they perform seasonal planning studies. The remaining three indicated that other entities perform the studies on their behalf.

Although nearly all entities indicated that they have a mechanism to receive planned outage data, many entities indicated that they only include outages in their seasonal planning process if the outage lasts the entire season or if they believe it would directly impact their system. Although 53 percent of respondents indicated that they account for equipment outages in seasonal studies, 40 percent indicated that they do not. It appears that entities that do not consider outages assume that all facilities are in-service. Nearly all entities indicated that they would communicate with neighboring Balancing Authorities (BA), TOPs, and the WECC RC if they identified unexpected operating conditions.

July 20, 2012 6


Many entities stated that “engineering judgment” is used in determining modeling parameters such as the inclusion of sub-100-kV elements, contingencies studied, consideration of relay settings, and other scenarios.

WECC base cases are used by many entities for seasonal studies. It is important to note that the level of modeling of sub-100-kV elements in WECC base cases is left up to the entity supplying data.3 For entities using their own models, sub-100-kV elements were typically only included for the entity’s own system.

Many entities indicated that they perform contingency analysis on all elements within their system, while others had varying methods for determining which contingencies to run. While 86 percent of entities indicated that they also consider contingencies external to their systems, 7 percent of entities indicated that they do not. In addition, of those that consider external contingencies, many indicated that this was only done for a few elements.

Although 67 percent of respondents indicated that they perform seasonal studies for shoulder periods, 24 percent indicated that they do not. Several entities indicated that the shoulder-season studies involved modeling varying loading levels, but did not consider changes in generation and transmission outages.

While 69 percent of respondents indicated that they share relay settings with neighboring TOPs for seasonal studies, 24 percent indicated that they do not. Many entities state that the relay settings are inherent in facility ratings because they were the limiting factor in determining those ratings. Also, many entities stated that they only share relay settings on tie lines with joint ownership.

Through participation in subregional planning groups, 58 percent of respondents participate in coordination of seasonal studies. Others also indicated participation in the building of WECC base cases. However, 9 percent of responses indicated no coordination process exists.

Identified Gaps • There is not a consistent method used for communicating planned outages

between TOPs and not all TOPs consider planned outages when performing seasonal studies. Outages are an important consideration in these models.

3 Caveat: Entities must provide the same level of detail that they would use in internal studies when making decisions related to system expansion and operating practices.

July 20, 2012 7


• There are no prescriptive criteria in base case development for which sub-100-kV elements are submitted by entities.

• There is inconsistency in identifying the contingencies for study in the seasonal study process.

• Many entities study shoulder periods simply by varying load levels, and not considering outages. The Report identified that on September 8, 2011, several significant outages were in place with high load levels.

• Many entities rely on communication of facility ratings to indirectly communicate relay settings.4 Ratings will cover system normal and emergency ratings but do not necessarily match up to relay settings. Entities need to know when the elements will trip, not just when they are overloaded. This was identified as an issue in the Report.

• Many entities do not model known outages in their seasonal studies and instead use the off-the-shelf WECC base cases that only model system conditions for anticipated seasonal peak-load and light-load periods.

• Participation in subregional planning groups is not universal. Scenarios studied are usually limited to seasonal path-rating studies and coordination is lacking in many cases.

• Entities had various ideas of what seasonal planning studies should entail. Some entities only study a subset of WECC paths within their system to determine seasonal operating limits on those paths, while others perform full contingency analysis of their system for the upcoming operating season.

Best Practices • Some entities represent their complete system, including sub-100-kV elements,

and monitor all elements within their model while performing full contingency analysis each season.

• Some entities include scheduled outages as part of their shoulder season studies. Outages are an important characteristic of shoulder seasons.

4 Many entities believe that relay settings are inherent in facility ratings where the relay is the limiting factor.

July 20, 2012 8


Near- and Long-Term Planning The Report included two recommendations on near- and long-term planning, and the survey included six questions related to those recommendations.

Summary of Results The vast majority of responses indicated that near- and long-term planning studies are performed under heavy transfer conditions. However, 15 percent of respondents indicated that peak operating conditions were used. It should be noted that these two types of condition are not necessarily the same.

Sub-100-kV facilities are incorporated in near- and long-term planning by 86 percent of respondents. Of those, 50 percent indicated that the facilities below 100 kV were limited.

Although 83 percent of respondents indicated that they account for protection systems in their near- and long-term planning studies, the remaining 17 percent do not. Those that do model protection systems were often limited to either internal systems or what appear in WECC base cases.

Roughly half of respondents indicated that they do some level of benchmarking of their models. Some entities that benchmark use real-time conditions, while others only look at specific events. Many responses pointed to the WECC Generator Testing Policy as a means of validating their models.

While 98 percent of responses indicated that protection is modeled in their dynamic simulation, only 2 percent indicated that it is not. The majority of entities rely on the data in the WECC base cases as the primary source.

The majority of entities have no plans to improve the dynamic models as a result of the September 8, 2011 event. Many said that they would continue to participate on the WECC Modeling and Validation Work Group to improve models.

Identified Gaps • There are inconsistencies in how entities prepare cases for studies, and not all

entities consider effects on sub-100-kV facilities for major transmission outages.

• There is limited communication between entities regarding protection systems and, in most cases, the examination of Remedial Action Schemes (RAS) was limited to those internal to their system. The majority of entities rely on what is in the WECC base cases for protection system models. Expansion of the WECC data requirements would be the quickest and most effective way to improve protection system modeling in WECC.

July 20, 2012 9


Best Practices • One entity is working to implement relays in dynamic simulations.

• One entity is working to move generator models to more robust models that will better capture response.

• One entity is planning to implement RAS models into dynamic simulation and improve modeling of generator controls.

Situational Awareness The Report included six recommendations on situational awareness, and the survey included six questions related to those recommendations.

Summary of Results Only 50 percent of TOPs indicated that they have Real-Time Contingency Analysis (RTCA). Of those that do not have RTCA, 20 percent indicated that they rely on the WECC RC and/or their host BA to perform RTCA. Several entities reported using nomograms and/or off-line power flow studies. It is unclear whether the WECC RC and host BAs always know that the TOP is relying on them for this role. In many cases, RTCA has limited visibility of external systems and often, only one bus.

Although 29 percent of the responding TOPs indicated that they do not have procedures for loss of real-time tools (including RTCA), 25 percent of them indicated that they are revising procedures to include this. Another 17 percent indicated that while there is not a formal procedure, their operators do call the WECC RC or send a WECCNet message identifying the loss.

Approximately 66 percent of respondents reported that they used some form of post-contingent mitigation processes. Some of these entities only use post-contingent measures to get below normal ratings, but use RAS action to get below emergency ratings. Of those that use post-contingent measures, only 85 percent share these processes with RCs and neighbors, and only two of the respondents considered timing of implementation in defining these measures.

A total of 69 percent of respondents indicated that they do some level of validation between their planning models and real-time models. In many cases, normal and contingency results of the real-time models are compared to study results of planning models to identify discrepancies. Two entities that do not have validation currently are working to develop tools and processes that would include this validation.

Approximately half of the TOPS had incorporated or were considering incorporating some of the recommendations from the NERC Real-Time Tools Best Practices Task

July 20, 2012 10


Force. However, five TOPs indicated that they had never heard of the task force or their recommendations prior to this survey.

Identified Gaps • Half of the TOPs, including several large TOPs, do not use RTCA. RTCA helps

TOPs with situational awareness to be able to develop mitigation plans for potential contingencies.

• A substantial number of TOPs do not have procedures in place to notify the WECC RC or neighbors for loss of real-time tools.

• Only two TOPs that use post-contingent mitigation processes indicated that they considered timing of implementation of these measures to prevent cascading. On September 11, 2011, there were only 11 minutes between the first event and the outage, so it is important to recognize that there may not be much time for manual action to be taken.

• Almost a third of TOPs do not take any steps to ensure consistency between planning and operating models.

• Several TOPs indicated that they were not aware of the recommendations from the Real-Time Tools Best Practices Task Force. All real-time operating entities should review the recommendations and consider incorporating them.

Best Practices • One TOP reported that its visibility of external systems extended six buses into

the neighboring systems. Though the optimal depth of visibility may differ between systems, it is good to consider looking deeper than one or two buses.

• One TOP noted that its internal procedure includes notifying not only the RC and neighboring TOPs for loss of real-time tools, but also other impacted entities.

• One entity reported setting a system operating limit for a thermally-limited path such that the most limiting element had at least 20 minutes before reaching the maximum temperature. This allowed for the ability to take measures prior to a contingency occurring.

• One TOP reported that they acquire a base case from the RC and review how generators and transformers are modeled in real-time and whether there are discrepancies between planning and operating models.

July 20, 2012 11


Consideration of Bulk Power System (BPS) Equipment The Report included one recommendation on Consideration of BPS Equipment, and the survey included one related question.

Summary of Results While 76 percent of the entities that responded to this survey question indicated that they consider sub-100-kV elements in their studies, there were many ways of deciding what would be included in studies. Some entities indicated that engineering judgment was used to determine what would be included. Other entities included all elements down to some lower voltage such as 69 kV. The final group identified facilities that were operated in parallel with 100-kV and above facilities as being included in studies performed. All of the entities that do not consider sub-100-kV elements either believe that they cannot affect reliability or the elements are operated radially.

Identified Gaps • There is not a consistent mechanism for identifying which sub-100-kV elements

are included in studies.

Best Practices • Considering sub-100-kV elements in studies is a prudent procedure. Studying

sub-100-kV elements to identify the impactful ones would provide the best coverage.

Protection Systems The Report included eight recommendations on protection systems, and the survey included seven questions related to the recommendations.

Summary of Results While 50 percent of entities do not have relay trip settings below 150 percent of normal rating or 115 percent of emergency ratings, 86 percent of those that do have lower relay trip settings share those settings. Approximately 66 percent of overall respondents indicated that they share any overload relay trip settings. Only 3 percent share settings with the RC.

While only 30 percent of respondents own or operate a RAS, half of them do not review their RAS until their studies indicate an issue or the TOP requests a study. The entities that do perform regular reviews of their RAS range from twice yearly to once every five years. The WECC RAS Review and Assessment Plan requires that each TO, GO, and DP assess their RAS for operation, coordination, and effectiveness at least once every five years.

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Approximately 33 percent of GO/GOP respondents do not plan to evaluate the performance of generators under severe or unusual system conditions. Most believe that WECC testing requirements or post-fault studies are adequate. Over 60 percent of GO/GOP respondents do not plan to evaluate the sensitivity of the acceleration control function. Only 20 percent plan to study this.

Identified Gaps • Some respondents indicated that only the settings on relays 200 kV and above

are reviewed.

• Most entities that own or operate a RAS do not have an internal process to review the operation, impact, and classification of their RAS.

• A substantial amount of GO/GOPs do not plan to evaluate the performance of generators under severe or unusual system conditions. Older units are not sensitive enough to ride-through conditions, so evaluation is necessary to set relays to be less sensitive.

Best Practices • Some RAS owner/operators review their RAS as often as twice a year.

Angular Separation The Report included one recommendation on Angular Separation, and the survey included three questions related to the recommendation.

Summary of Results Only 40 percent of TOP respondents indicated that they have the capability to see standing angles in real-time. Of the 52 percent that said they did not have the capability to see standing angles, 14 percent said that they are working on developing this capability. The RC can determine standing angles that would result following major transmission outages through real-time state estimation. In addition, the RC is implementing monitoring of expected post-contingent standing angels on several important paths.

Only 38 percent of respondents indicated that they have Phasor Measurement Units (PMU) or digital relays installed and of these, 36 percent indicated that the location selection was based on focusing on major transmission, often identified as higher voltage facilities, followed by intertie points. Another 50 percent indicated that the location was selected in coordination with the Western Interconnection Synchrophasor Project (WISP), which also focused on major transmission facilities first. The remainder indicated they had installed digital relays when it was time to replace older equipment, including analog relays.

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In considering plans for reducing standing angles, 26 percent of respondents indicated that they have plans; 24 percent indicated that while they do not have specific plans, they train their operators in various measures that can be taken to reduce standing angles; and 38 percent do not have any predetermined plans for reducing standing angles. The RC does not have a plan for reducing standing angles within synchro-check relay settings.

Identified Gaps • A large percentage of TOPs do not have the ability to estimate the standing

angles that would result from major transmission outages. This can in some cases impede restoration after a major outage, as was seen in the September 8, 2011 event.

• Many TOPs have not installed PMUs or digital relays and did not mention any plans for future installation

• One entity noted that although PMUs are installed to monitor their higher voltage system, the operators do not have access to the data and there are no plans to incorporate this data into its Energy Management System (EMS).

• Many TOPs do not have plans to reduce standing angles and did not mention training operators in measures that can be taken to reduce standing angles.

Best Practices • One entity responded that in addition to visibility of PMU data on EMS displays,

its system operators have the capability to remote synchronize individual islands. This remote synchronization provides phase angle differences, voltage, and frequency at many significant locations.

• One respondent noted that PMU data will be streamed in the Plant Information (PI) historian and be available to dispatchers in real-time, including deployment of phase angle monitoring applications and phase angle alarm displays.

• One respondent had a specific plan for phase angle closing problems during major outages that provides direction on specific measures to reduce angles for specific major transmission lines.

Other The survey also allowed respondents to enter any additional comments or concerns. Several entities noted that there may be issues with overall processes and policies, including the planning process, path rating process, communications between planning and operations, standards, and human performance. Others noted that data sharing is a major issue that must be addressed.

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Next Steps WECC staff is working with the WECC Standing Committees to identify initiatives to mitigate the gaps found by the survey.

July 26, 2012 Mr. Mark Maher Western Electricity Coordinating Council 155 North 400 West, Suite 200 Salt Lake City, UT 84103 Dear Mark, On May 1, 2012, the Federal Energy Regulatory Commission (FERC) and NERC released a joint report summarizing the causes and findings of our eight-month review of the September 8, 2011 Southwest event affecting nearly three million customers in Southern California, Arizona, and Baja California, Mexico. The report identified 27 recommendations for preventing similar future events in the West. I appreciate your responsive leadership since the issuance of the report to initiate quick remediation of many of the most urgent issues needed to ensure a reliable Western Interconnection through the peak summer period. The weekly calls to review progress have also been helpful. I understand also that you are working on longer term plans to address all of the recommendations in the report. Additionally, I want to thank you for the timely response to the June 5, 2012 letter issued by David Nevius, NERC’s executive director of the event review, requesting a status report on follow-up actions by registered entities and WECC itself. To date there appears to be substantive and responsive actions to remediate a number of the specific causes of the September 8 event. I have also had a number of follow-up meetings with senior executives from the West, including with the WECC board in late June and the Western Electric Industry Leaders group in July, and I am pleased with the level of acknowledgement of a need for substantive changes and improvements to the management of reliability in the Western Interconnection. I believe, however, that many of the findings of the report point to underlying systemic or institutional issues with the management of reliable interconnected operations and planning, and with the culture of reliability in the Western Interconnection. These concerns are reinforced by some of the initial gaps identified in your July 20 white paper outlining aggregated responses to a survey conducted by WECC. The responses indicate broad gaps involving entities beyond the parties involved in the September 8 event with regard to situational awareness, reliability information sharing, system reliability analysis and planning, and system protection coordination, to name a few. The purpose of this letter is to request that you provide to NERC, no later than August 31, 2012, a detailed report outlining near-term remediation actions completed or in progress to date, and plans for additional actions going forward. The forward-looking portion of the report should provide a description of the objectives and deliverables planned to address the 27 recommendations from the FERC-NERC report, as well as the eight broader systemic issues I have outlined below. I understand that by August 31, some of the longer-term actions may only have a plan of action, but may not yet

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have been initiated. For each recommendation and issue below, the report should provide a summary of actions planned and a timetable of milestones by which we can track progress with you. Although there may be other specific remediation plans with individual entities directly involved in the September 8 event, I think there is a great opportunity for WECC, under your leadership, to pull together the comprehensive, Interconnection-wide response to address the recommendations and issues from this event. The systemic or institutional concerns that I have identified are summarized below. Some of these issues are related to one or more of the recommendations from the FERC-NERC report, while others address broader underlying concerns:

1. WECC Reliability Coordinator Tools, Authorities, Capabilities and Support

Ensure sufficient staff resources, tools, and training.

Ensure that registered entities understand and expect reliability coordinator authority will be exercised when needed, and with the appropriate degree of urgency in cases of potential cascading situations.

Ensure the reliability coordinator is willing to assert authority when a reliability issue is identified.

Ensure reliability coordinator has situational awareness of the entire bulk electric system in the Western Interconnection.

Benchmark reliability coordinator capabilities and performance compared to other reliability coordinators.

2. WECC Organization, Governance and Conflict of Interest

Consider separating governance of functions delegated by NERC from registered entity functions.

Consider establishing a smaller, more effective board for the regional entity functions; consider what is an effective balance of independent directors and stakeholder directors.

Ensure additional roles for the region (e.g. reliability coordinator, planning coordinator, energy imbalance market, etc.) are separated from NERC delegated functions; NERC has no opinion on the governance of these other functions.

3. WECC Path Ratings and Interconnection Reliability Operating Limits (IROLs)

Ensure all IROLs are identified and updated dynamically based on changing system configuration.

Ensure path limits are updated; not depending solely on long-term or seasonal studies.

Resolve path operator responsibilities – who has Transmission Operator (TOP)/Transmission Owner (TO) responsibilities for all facilities that comprise each rated path.

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4. System Protection, Remedial Action Schemes, and Special Protection Systems

Evaluate any potential risks introduced by a proliferation of remedial and special protection schemes and safety nets; ensure all schemes are coordinated with each other and general system protection.

Ensure awareness, recognition, and communication of operating limits created by relay settings.

5. Data Sharing, Non-Disclosure and Data Confidentiality Agreements

Establish a culture of trust in reliability data sharing; overcome current barriers to data sharing.

All reliability coordinators, transmission operators, and balancing authorities should have access to all reliability data necessary to perform their next-day and real-time reliability assessments; includes neighboring systems and in some cases interconnection-wide data.

Complete the execution of the universal NDA to allow data sharing for next-day studies among all transmission operators, balancing authorities and reliability coordinators.

6. Roles and Responsibilities of Reliability Coordinator (RC), Balancing Authorities, and TOPs

Evaluate and clarify roles and responsibilities of all entities, including small, local entities.

Ensure transmission operators, including small ones, have adequate situational awareness and system visibility and are conducting same-day real-time contingency analysis.

De-register entities not capable of performing functions for which registered and transfer their responsibilities or require joint registration organizations.

7. Awareness and Recognition of Impacts of Sub-100 kV Systems on Bulk Power System Reliability

Evaluate the entire system to identify any sub-100 kV facilities that could potentially lead to cascading outages.

Ensure active monitoring and alarming of all such facilities by the WECC RC.

8. ERO/Regional Entity (RE) Processes

In collaboration with NERC, review the history of ERO and WECC RE reliability oversight to understand why underlying conditions were not identified and addressed; to include regional studies and modeling; compliance monitoring activities and what actions should be taken going forward.

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Once again, thank you for your responsive leadership at this critical time in addressing the issues outlined in the report and in this letter. I also want to thank the executive leadership within the Western Interconnection for stepping up at this critical time to help you lead these efforts, particularly the Western Electric Industry Leaders group, whom I have copied on this letter. Sincerely,

Gerry Cauley President and CEO cc: Western Electric Industry Leaders

Chairman Jon Wellinghoff, Federal Energy Regulatory Commission Honorable Phillip D. Moeller, Federal Energy Regulatory Commission Honorable John R. Norris, Federal Energy Regulatory Commission Honorable Cheryl A. LaFleur, Federal Energy Regulatory Commission Honorable Tony Clark, Federal Energy Regulatory Commission Mr. Jim Pederson, Federal Energy Regulatory Commission Mr. Norman Bay, Federal Energy Regulatory Commission Mr. Mike Bardee, Federal Energy Regulatory Commission Mr. Joseph McClelland, Federal Energy Regulatory Commission NERC Board of Trustees NERC Executive Management Group


Update on Regulatory Matters (As of July 18, 2012)

Action Required None

Background Regulatory Matters in Canada

1. Negotiation of the second agreement among NERC, the Régie and NPCC regarding implementation of mandatory standards in Québec has been tentatively concluded and the agreement is under consideration by the provincial government. The Régie has issued a preliminary decision regarding adoption of mandatory standards for Québec.

2. Adoption of NERC Reliability Standards ongoing in Alberta.

3. Implementing regulations have been adopted in Manitoba.

4. Implementing regulations being developed in British Columbia.

5. a. Quarterly filings to request approval of FERC approved Reliability Standards in Nova Scotia.

b. June 25, 2012 – Nova Scotia Utility and Review Board issued a Letter to NERC regarding its Board Process for Review of Quarterly Applications for Approval of Reliability Standards. NERC-R-11 – Matter No. M05027

6. Ontario reconsidering how compliance and enforcement program is administered within the province.

7. New Brunswick reconsidering how compliance and enforcement program is administered within the province.

FERC Orders Issued Since the Last Update

1. April 19, 2012 – FERC issued an Order approving the eight modified Critical Infrastructure Protection Reliability Standards (CIP-002-4 through CIP-009-4), the related Violation Risk Factors, Violation Severity Levels with modifications, implementation plan and effective date. Docket No. RM11-11-000 (Order No. 761)

2. April 19, 2012 – FERC issued a Notice of Proposed Rulemaking in which it proposes to remand proposed Reliability Standard, TPL-001-2. Docket No RM12-1-000

3. April 19, 2012 – FERC issued an order in which it remands proposed Transmission Planning (TPL) Reliability Standard TPL-002-0b. Docket No. RM11-18-000 (Order No. 762)

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4. April 19, 2012 – FERC issued an Order Granting the Compliance Registry appeal of the US. Department of Energy, Portsmouth/Paducah Project Office. The Order also remanded for further proceeding the issue of whether NERC should register Ohio Valley Electric Corporation as a Load-Serving Entity. Docket No. RC08-5-001

5. April 19, 2012 – FERC issued an Order Denying the Compliance Registry appeal of the City of Holland, Michigan Board of Public Works. Docket No. RC11-5-000

6. April 19, 2012 – FERC issued a Notice of Proposed Rulemaking proposing to amend its regulations to incorporate by reference the business practice standards adopted by the Wholesale Electric Quadrant of the North American Energy Standards Board (NAESB) that pertain to the measurement and verification of demand response and energy efficiency resources participating in organized wholesale electricity markets. Docket No. RM05-5-020

7. April 19, 2012 – FERC issued a Notice of Inquiry in which it seeks to explore whether, and, if so, how the Commission should revise its current policy concerning priority rights and open access with regard to certain interconnection facilities. Docket No. AD11-11-000

8. April 23, 2012 – FERC issued a notice inviting comments upon a report prepared by the Pacific Northwest National Laboratory (PNNL) on “Applicability of the ‘Gallet Equation’ to the Vegetation Clearances of NERC Reliability Standard FAC-003-2” (PNNL Report). Docket No. RM12-4-000

9. April 27, 2012 – FERC issued an Order stating that it would not further review, on its own motion, the following Notices of Penalty in NP12-19-000 American Electric Power Service Corporation as agent for Public Service Company of Oklahoma & SW Electric Power Company; NP12-20-000 Unidentified Registered Entity; NP12-21-000 Sunflower Electric Power Corporation; and NP12-22-000 Spreadsheet NOP.

10. May 4, 2012 – FERC issued an order on NERC's Motion for an Extension of Time and established a compliance schedule for NERC to submit a revised BAL-003 Reliability Standard consistent with the Commission’s directives in Order No. 693. Docket Nos. RM06-16-010 and RM06-16-011

11. May 4, 2012 – FERC issued a data request in response to NERC's Petition for Approval of Proposed Reliability Standard FAC- 003-2 – Transmission Vegetation Management order to better understand NERC’s petition. Docket No. RM12-4-000

12. May 7, 2012 – FERC issued a Final Rule approving Reliability Standards PRC-006-1 (Automatic Underfrequency Load Shedding) and EOP-003-2 (Load Shedding Plans), with modifications. Docket No. RM11-20-000 (Order No. 763)

13. May 17, 2012 – FERC issued a Letter Order regarding FAC-013-2 in which it accepted the January 17, 2011 compliance filing in which NERC submitted a response to the November 17 Order. NERC clarified the Violation Severity Level language in Requirement R1, as set out in the November 17 Order, and proposed that Requirements R1 and R4 be assigned a Violation Risk Factor of Medium. Docket No. RD11-3-000

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14. May 17, 2012 – FERC issued a Letter Order accepting a compliance filing in which NERC proposed to assign a Medium Violation Risk Factor for Requirement R2 of FAC-008-3, as directed in the November 17 Order. Docket No. RD11-10-000

15. May 30, 2012 – FERC issued an Order stating that it would not further review, on its own motion, the following Notices of Penalty in NP12-23-000 Southern California Edison – Generation – Power Production Business Unit; NP12-24-000 East Kentucky Power Cooperative; NP12-25-000 Unidentified Registered Entity; and NP12-26-000 Spreadsheet NOP.

16. May 31, 2012 – FERC issued an Order granting in part and denying in part, NERC’s request for Clarification of the March 15, 2012 Order, and denying the alternative request for rehearing. The March 2012 Order approved the FFT Compliance Enforcement Mechanism and on April 16, 2012, NERC asked for clarification on the certification statement of mitigation activities associated with remediated issues. Docket No. RC11-6-001

17. May 31, 2012 – FERC issued an Order in which it approved the Regional Reliability Standard IRO-006-TRE-1, associated Violation Risk Factors and Violation Severity Levels, and the implementation plan. Docket No. RD12-1-000

18. May 31, 2012 – FERC and NERC issued a report on the Transmission Facility Outages during the Northeast Snowstorm of October 29, 2011 through October 30, 2011.

19. June 12, 2012 – FERC issued a Letter Order approving NERC's March 15, 2012 filing which contained amendments to SERC's Delegation Agreement. Docket No. RR12-5-000

20. June 12, 2012 – FERC issued a Letter Order approving NERC's February 22, 2012 filing which contained amendments to FRCC's Delegation Agreement. Docket No. RR12-4-000

21. June 13, 2012 – FERC issued an Order accepting NERC's December 2, 2011 Compliance Filing in response to the June 16, 2011 Order denying the registration appeals of Cedar Creek Wind Energy, LLC and Milford Wind Corridor Phase I, LLC. Docket Nos. RC11-1-002 and RC11-2-002

22. June 14, 2012 – FERC issued an order terminating its Notice of Inquiry seeking comments regarding whether there are conflicts between NERC Reliability Standard IRO-006-4 (Reliability Coordination - Transmission Loading Relief (TLR)) and the curtailment priorities set forth in the Commission’s pro forma Open Access Transmission Tariff (OATT). . Docket No. RM10-9-000

23. June 20, 2012 – FERC issued a letter to NERC requesting the status of the initiative to modify Reliability Standards to address winterization and related issues and a status report on NERC’s anticipated timeline for filing with the Commission any proposed new or revised Reliability Standards. Docket No. AD11-9-000

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24. June 21, 2012 – FERC issued an Order denying rehearing and providing clarification on the April 18, 2011 requests for clarification of the March 17, 2011 Order on Review of Notice of Penalty involving Turlock Irrigation District. Docket No. NP10-18-002

25. June 22, 2012 – FERC issued a final rule on the Integration of Variable Energy Resources in which it amended the pro forma Open Access Transmission Tariff to remove unduly discriminatory practices and to ensure just and reasonable rates for Commission-jurisdictional services. Docket No. RM10-11-000 (Order No. 764)

26. June 22, 2012 – FERC issued a Notice of Proposed Rulemaking on NERC's Definition of Bulk Electric System and Rules of Procedure in which it proposed to approve NERC's definition. Docket Nos. RM12-6-000 and RM12-7-000

27. June 25, 2012 – FERC issued a Letter Order approving NERC's May 17, 2012 petition for amendments to the delegation agreement with Midwest Reliability Organization. Docket No. RR12-9-000

28. June 29, 2012 – FERC issued an Order stating that it would not further review, on its own motion, the following Notices of Penalty in Docket Nos. NP12-27-000 Spreadsheet NOP; NP12-29-000 Unidentified Registered Entity; and NP12-30-000 American Electric Power Service Corporation

29. July 19, 2012 – FERC issued a Notice of Proposed Rulemaking on NERC's February 1, 2012 Petition for Approval of Regional Reliability Standard PRC-006-SERC-01 in which it proposed to approve the Regional Standard. Docket No. RM12-9-000

30. July 19, 2012 – FERC issued an Order on Review of a Notice of Penalty regarding Southwestern Power Administration. Docket No. NP11-238-000

NERC Filings Since the Last Update

1. April 30, 2012 – Informational report on the analysis of NERC Standards Process Results for the First Quarter 2012 in compliance with an order issued by FERC on January 18, 2007 and a subsequent order on September 16, 2010. Docket Nos. RR06-1-015

2. April 30, 2012 – April 2012 Find, Fix and Track Report Filing. Docket No. RC12-11-000

3. April 30, 2012 – Notices of Penalty regarding the following entities in Docket Nos. NP12-23-000 Southern California Edison - Generation - Power Production Business Unit; NP12-24-000 East Kentucky Power Cooperative; NP12-25-000 Unidentified Registered Entity; and NP12-26-000 Spreadsheet Notice of Penalty; and NP12-31-000

4. May 3, 2012 – Request for Information on the Notice Inviting Comments regarding documents pertaining to the PNNL Report concerning the applicability of the Gallet Equation. Docket No. RM12-4-000

5. May 4, 2012 –Petition for Approval of Proposed NPCC Regional Reliability Standard PRC-006-NPCC-1— Automatic Underfrequency Load Shedding. Docket No. RM12-12-000

6. May 7, 2012 – Petition for Approval of revisions to NERC Rules of Procedure Sections 300, 400, 600, 1000, 1400 and 1700 and to Appendices 2, 4B, 4C, and 5B, and the

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deletion of Appendices 3C and 6 to the NERC Rules of Procedure. Docket No. RR12-8-000

7. May 14, 2012 – Report on Compliance Enforcement Initiative in compliance with the March 15, 2012 Order where FERC accepted NERC's petition requesting approval of its proposal to make informational filings in a Find, Fix, Track and Report spreadsheet format in connection with the Compliance Enforcement Initiative. Docket No. RC11-6-000

8. May 14, 2012 – Compliance Filing in response to the March 15, 2012 Order where FERC accepted NERC's petition requesting approval of its proposal to make informational filings in a Find, Fix, Track and Report spreadsheet format in connection with the Compliance Enforcement Initiative. Docket No. RC11-6-002

9. May 15, 2012 – Request for Rehearing of the May 4, 2012 Letter Order issued by Office of Enforcement regarding the Audit. Docket No. FA11-21-000

10. May 15, 2012 – Statement on Procedures in response to the May 4, 2012 Letter Order issued by Office of Enforcement regarding the Audit. Docket No. FA11-21-000

11. May 17, 2012 – Petition for Approval of amendments to the Delegation Agreement with Midwest Reliability Organization. Docket No. RR12-9-000

12. May 21, 2012 –Request for Rehearing and Clarification in connection with the April 19 Order which granted an appeal filed by the United States Department of Energy, Portsmouth/Paducah Project Office and found that it should not be registered as a load-serving entity under the NERC Statement of Compliance Registry Criteria. Docket No. RC08-5-002

13. May 21, 2012 – Request for Reconsideration, or in the Alternative, Rehearing of Order Remanding the Transmission Planning Reliability Standards. Docket No. RM11-18-001

14. May 21, 2012 – Comments following the FERC Technical Conference held on April 30, 2012 regarding Geomagnetic Disturbances to the Bulk Power System. Docket No. AD12-13-000

15. May 23, 2012 – Petition for Approval of Interpretation to Reliability Standard CIP-006 – Cyber Security — Physical Security of Critical Cyber Assets. This interpretation will be known as either CIP-006-3d or CIP-006-4d, whichever version of the standard is in effect at the time of FERC approval. Docket No. RD12-3-000

16. May 23, 2012 – Letter submitted to FERC regarding the Audit. Docket No. FA11-12-000

17. May 23, 2012 – Comments in response to the report prepared by the Pacific Northwest National Laboratory on “Applicability of the ‘Gallet Equation’ to the Vegetation Clearances of NERC Reliability Standard FAC-003-2." Docket No. RM12-4-000

18. May 24, 2012 – Petition for Renewals of the Compliance Monitoring and Enforcement Agreements between SERC Reliability Corporation and Florida Reliability Coordinating Council and SERC Reliability Corporation and Southwest Power Pool Regional Entity, and amendments to "Exhibit A to the Amended and Restated Delegation Agreement" of

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both agreements to reflect the effective date of the agreement. Docket No. RR12-10-000

19. May 25, 2012 – Response to the FERC Office of Electric Reliability’s May 4, 2012 Data Request regarding FAC-003-2. Docket No. RM12-4-000

20. May 30, 2012 – True-up filing to provide comparisons of actual to budgeted costs for the year 2011 for NERC and the eight Regional Entities. Docket No. RR12-11-000

21. May 30, 2012 – May 2012 Find, Fix and Track Report Filing. Docket No. RC12-12-000

22. May 30, 2012 – Notices of Penalty regarding the following entities in Docket Nos. NP12-27-000 Spreadsheet Notice of Penalty; NP12-28-000 Southern California Edison - Transmission & Distribution Business Unit; NP12-29-000 Unidentified Registered Entity; NP12-30-000 American Electric Power Service Corporation; and NP12-31-000 San Diego Gas & Electric

23. May 31, 2012 – First Quarter 2012 Compliance Filing in Response to Paragraph 629 of Order No. 693. Order No. 693 requires that NERC provide a quarterly informational filing regarding the timeframe to restore power to the auxiliary power systems of U.S. nuclear power plants following a blackout as determined during simulations and drills of system restoration plans. Docket No. RM06-16-000

24. June 5, 2012 – Petition for Approval of proposed errata changes to Reliability Standards BAL-005-0.2b: Automatic Generation Control; EOP-001-0.1b: Emergency Operations Planning; EOP-001-2.1b: Emergency Operations Planning; EOP-002-3.1: Capacity and Energy Emergencies; IRO-005-3.1a: Reliability Coordination – Current Day Operations; PER-001-0.2: Operating Personnel Responsibility and Authority; and TOP-002-2b: Normal Operations Planning. Docket No. RD12-4-000

25. June 6, 2012 – Limited Motion to correct the record in regard to the Commission’s Final Rule in Order No. 763 issued on May 7, 2012. Docket No. RM11-20-000

26. June 7, 2012 – Answer to the comments filed in response to NERC’s Petition for Approval of Revisions to its Rules of Procedure filed on May 7, 2012. Docket No. RR12-8-000

27. June 14, 2012 – Withdrawal of Full Notice of Penalty in connection with the May 30, 2012 submitted Full Notice of Penalty regarding Southern California Edison - Transmission & Distribution Business Unit. Docket No. NP12-28-000

28. June 14, 2012 – Withdrawal of Full Notice of Penalty in connection with the May 30, 2012 submitted Full Notice of Penalty regarding San Diego Gas & Electric. Docket No. NP12-31-000

29. June 19, 2012 – Response to the Commission’s June 4, 2012 Order on Procedures regarding the Audit. Docket No. FA11-21-000

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30. June 20, 2012 – Doc-less Motion to Intervene in response to the Notice of Inquiry issued by FERC on April 19, 2012 regarding whether and what changes should be made to the Commission’s policy on priority rights and open access to interconnection facilities could have on reliability impacts. Docket No. AD12-14-000, et. al.

31. June 29, 2012 – June 2012 Find, Fix and Track Report Filing. Docket No. RC12-13-000

32. June 29, 2012 – Notices of Penalty regarding the following entities in Docket Nos. NP12-32-000 Calpine Corporation and Calpine Power Management, LP; NP12-33-000 Louisville Gas and Electric Company and Kentucky Utilities Company; NP12-34-000 Tennessee Valley Authority; NP12-35-000 Mesquite Power LLC; and NP12-36-000 Spreadsheet Notice of Penalty.

33. July 2, 2012 – First Quarterly filing on the status of the development of the CIP Version 5 Reliability Standards. Docket No. RM11-11-000

34. July 5, 2012 – Response to FERC Office of Electric Reliability’s letter regarding NERC’s initiative to modify the Reliability Standards to address winterization and related issues. Docket No. AD11-9-000

35. July 18, 2012 – Compliance Filing on Ohio Valley Electric Cooperative as load-serving entity in response to the April 19, 2012 Order. RC08-5-001

36. July 19, 2012 – Initial Brief responding to the recommendations in the Audit Report. Docket No. FA11-12-000

37. July 20, 2012 – Response to the April 19, 2012 Notice of Proposed Rulemaking on TPL-001 Reliability Standards. Docket No. RM12-1-000

Anticipated NERC Filings

1. July 30, 2012 – Compliance Filing in response to P 27 of Order No. 758, a status report on PRC-005-2 including project schedule for addressing reclosing relays in PRC-005-3. Docket No. RM10-5-000

2. July 31, 2012 – NERC must submit a quarterly filing to keep the Commission informed of continual progress with Frequency Response and revised BAL-003 standard. (See March 30, 2012 filing for new proposal). Docket No. RM06-16-010

3. July 31, 2012 – NERC must submit quarterly reports within 30 days of the end of each quarterly period, beginning with the fourth quarter of 2010, through and including the fourth quarter of 2013, on voting results in the Reliability Standards Development Process (see P 85 of the September 16, 2010 Order on the Three-Year Performance Assessment) Docket Nos. RR09-7-000 and AD10-14-000

4. August 9, 2012 – NERC must submit a compliance filing in Response to Order No. 763 approving PRC-006-1 and EOP-003-2. NERC must submit revisions to a VRF and VSL, and a plan for complying with a Commission directive in modifying the Reliability Standard PRC-006-1. Docket No. RM11-20-000

5. August 31, 2012 – Nova Scotia Quarterly Filing of FERC Approved Reliability Standards

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6. August 31, 2012 – Quarterly NUC filing in response to Paragraph 629 of Order No. 693. Docket No. RM06-16-000.

7. September 4, 2012 – NERC must submit comments in response to the June 22, 2012 Notice of Proposed Rulemaking on Revisions to Electric Reliability Organization definition of Bulk Electric System and Rules of Procedure. Docket No. RM12-6-000 and RM12-7-000

8. September 7, 2012 – NERC may submit reply briefs in response to the August 18, 2012 third party briefs. Docket No. FA11-12-000

9. September 17, 2012 – NERC must submit comments in response to the July 19, 2012 Notice of Proposed Rulemaking on Regional Reliability Standard PRC-006-SERC-01 (earliest date, comments are due 60 days after publication in the Federal Register). Docket No. RM12-9-000

10. October 31, 2012 – NERC must submit quarterly reports to explain whether it is on track to meet deadline and describe status of its CIP standard development efforts for CIP V5 Standards. (See Order No. 761 at P4) Docket No. RM11-11-000

11. October 31, 2012 – NERC must submit a quarterly filing to keep the Commission informed of continual progress with Frequency Response and revised BAL-003 standard. (See March 30, 2012 filing for new proposal). Docket No. RM06-16-010

12. October 31, 2012 – NERC must submit quarterly reports within 30 days of the end of each quarterly period, beginning with the fourth quarter of 2010, through and including the fourth quarter of 2013, on voting results in the Reliability Standards Development Process (see P 85 of the September 16, 2010 Order on the Three-Year Performance Assessment) Docket Nos. RR09-7-000 and AD10-14-000

13. November 30, 2012 – Quarterly NUC filing in response to Paragraph 629 of Order No. 693. Docket No. RM06-16-000.

14. November 30, 2012 – Nova Scotia Quarterly Filing of FERC Approved Reliability Standards

July 11, 2012 Mr. Scott Helyer, Chair NERC Member Representatives Committee Vice President, Transmission Tenaska, Inc. 1701 E. Lamar Blvd. Arlington, Texas 76006 Re: Policy Input to NERC Board of Trustees Dear Scott: During the past two quarterly meetings of 2012, the Board of Trustees (Board) has requested and received thoughtful policy input from the Member Representatives Committee (MRC) and shared in the discussion of a number of critical issues. I would like to continue this trend of active dialogue for the upcoming meetings in August by requesting the MRC’s feedback on a few issues of current interest to the Board. As always, I welcome input on any other items that stakeholders wish to provide. I understand the agendas for the MRC and Board meetings are expected to be posted by August 1, 2012. 2013 NERC and Regional Entity Common Business Plan and Budget — Each year, NERC and the Regional Entities devote time and effort to refine and update goals, objectives, deliverables, and common multi-year business planning and budgeting assumptions, taking into account lessons learned and stakeholder feedback, as well as applicable governmental requirements and directives. The Board would like to receive any additional comments and input to the 2013 Business Plan and Budget (BP&B) and associated assessments for NERC and the Regional Entities. I particularly invite input on the scope of the issues addressed within the BP&B as they relate to NERC’s core responsibilities (i.e., standards development, compliance, and reliability assessments), the high priority items for 2013, the challenges and demands facing the ERO’s strategic objectives, and the projections for 2014-2015. The Board also welcomes comments on prioritizing shared responsibilities for reliability solutions among NERC, industry, and other partnerships. Recommendations of the Standards Process Input Group (SPIG) — On May 9, 2012, the Board endorsed five recommendations of the SPIG and requested a status update during the August meetings regarding progress made towards each issue. Based on the recent activities and various comment opportunities of the Standards Committee, the SPIG, and NERC staff, I encourage the MRC to share how progress is being perceived towards each of the five recommendations. Additionally, the

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Board is expecting to be asked to take action on a scope/charter document for the Reliability Issues Steering Committee (RISC) and an accompanying slate of proposed members for the new committee. Considering the timeliness of the August meetings, the MRC is encouraged to provide comment on any other issues that are meaningful to industry and stakeholders to include areas of significance to Canada. Written comments should be sent to Holly Mann, MRC Secretary ([email protected]) by August 6, 2012 so the Board may receive and review in advance of the meeting. Thank you,

John Q. Anderson, Chair NERC Board of Trustees cc: NERC Board of Trustees

Member Representatives Committee Regional Executives


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