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Agenda Member Representatives Committee November 6, 2012 | 1:00-5:00 p.m. Central JW Marriott New Orleans 614 Canal Street New Orleans, LA 70130 504-525-6500 Introductions and Chair’s Remarks NERC Antitrust Compliance Guidelines and Public Meeting Notice Consent Agenda

1. Minutes* ― Approve

a. October 5, 2012 Conference Call

b. August 15, 2012 Meeting

2. Future Meetings*

3. Elections and Nominations*

a. Election of MRC Officers for 2013 and Sector Elections

b. Update on MRC Sector Nominations and Election

c. Update from the Board of Trustees Nominating Committee

4. Remarks from Gerry Cauley, NERC President and CEO

a. Strategic initiatives

b. FERC restructuring

5. Status Reports on Policy Initiatives*

a. Standards process reform

i. Standards Process Input Group (SPIG)

b. Compliance Enforcement Initiative

i. CEI Endstate Input Group

c. ERO Scope of Activities Input Group

6. Initial Report on Reliability Issues Steering Committee (RISC) Activities Priorities*

Member Representatives Committee Agenda November 6, 2012

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7. Discussion and Policy Input for Select Standards Projects*

a. Review of select Reliability Standards projects

b. Reliability Standards status report

c. Adequate Level of Reliability

8. Revisions to Rules of Procedure Appendix 4D on Technical Feasibility Exception*

9. Additional Discussion of MRC Informational Session Items, October 30

10. Follow-Up Activities from the Arizona-Southern California Outage*

11. Regulatory Update*

12. Comments by Outgoing Chair and Chair-Elect

*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 October 5, 2012 | 11:00 a.m. Eastern Chair Scott Helyer convened a duly‐noticed open meeting by conference caraftll of the North American Electric Reliability Corporation’s Member Representatives Committee (MRC) on October 5, 2012 at 11:00 a.m. local time. 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 a quorum was not 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 Proposed MRC Agenda Items: October 30 and November 6, 2012 The preliminary agenda items were shared, via a slide presentation, for the upcoming October 30 MRC Informational Session and the November 6 meeting in New Orleans, Louisiana (Exhibit D). Proposed topics for discussion during these meetings include: October 30 – updates on the 2012 reliability issues information sharing conference (November 28), gas‐electric interdependency, event analysis process, 2012 long term reliability assessment and emerging issues, and the frequency response technical report. November 6 – updates on MRC elections and nominations, ERO strategic planning initiatives, standards process reform, compliance and enforcement and ERO scope initiatives, reliability issues steering committee (RISC) activities, select standards projects, rules of procedure revisions, and follow‐up activities from 2011 southwest outage. Additional time will be given during the November 6 meeting to discuss topics from the October 30 MRC Informational Session. Review of Proposed Board of Trustees and Board Committees’ Meeting Agenda Items The preliminary agenda items were shared, via a slide presentation, for the Board of Trustees and Board Committees’ meetings scheduled for November 6‐7 in New Orleans, Louisiana (Exhibit D). The MRC was reminded of the Board’s request to provide policy input on several current issues which include the timeliness and quality of the current standards development process, the progress of the compliance enforcement initiative and the March 2013 filing to FERC, the use of three‐part operator communications in NERC standards, and the revisions to the definition of adequate level of reliability.

MRC Pre-meeting Conference Call Draft Minutes –– October 5, 2012

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The letter requesting policy input from the MRC was distributed on October 5, following the pre‐meeting call. Schedule of Events for Upcoming Meetings The draft schedule of events for the upcoming meetings in New Orleans was provided as Exhibit E. 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 November 6. Committee Nominations Scott Helyer announced the upcoming election of the MRC officers will be conducted on November 6 and the MRC sector nomination period closes on November 13. Proxy Reminder MRC members were reminded that proxy notifications for the November 6 meeting must be submitted in writing to Holly Mann, MRC secretary. Meeting Adjourned There being no further business, the call was terminated at 11:45 a.m. local time. Submitted by,

Holly Mann Committee Secretary

Draft Minutes Member Representatives Committee (MRC) August 15, 2012 | 1:00–5:00 p.m. ET Hilton Quebec 1100, Rene-Levesque Blvd East Quebec, QC Canada G1R 4P3 Chair Scott Helyer called to order the North American Electric Reliability Corporation (NERC) Member Representatives Committee (MRC) meeting on August 15, 2012 at 1:00 p.m., local time. 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, indicating that any questions regarding these guidelines or notice should be addressed to NERC’s General Counsel, Charles Berardesco. Introductions and Chair’s Remarks Chair Helyer declared a quorum present with the following recognized proxies:

• Barry Lawson for Eric Baker – Cooperative

• Bill Gallagher for Terry Huval – Transmission Dependent Utility

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

• Scott Helyer for William Taylor III – Merchant Generator

• Lam Chung for Lorne Midford – Federal/Provincial

• Stacy Dochoda for Gordon Gillette – Regional Entity - FRCC (non-voting) Chair Helyer acknowledged and welcomed Vice Chair Carol Chinn, the NERC Board of Trustees, Commissioners Cheryl LaFleur and John Norris, Federal Energy Regulatory Commission (FERC), and Pat Hoffman, assistant secretary for electricity delivery and energy reliability, U.S. 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. Minutes The MRC approved the draft minutes of its July 10, 2012 conference call and May 8, 2012 meeting (Exhibits D and E).

MRC Draft Minutes August 15, 2012

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Nominations and Election of MRC Officers and Sector Representatives Chair Helyer announced the annual nomination and election of the MRC chair, vice chair and member representatives from each sector. The tentative schedule for the 2013 elections includes: MRC Officer Nominations and 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 Update from the Board of Trustees Nominating Committee Jan Schori, chair of the Board of Trustees Nominating Committee (BOTNC), reported that the BOTNC continues the recruitment of candidates for the Board. John Q. Anderson and Tom Berry will be term limited in February 2013 and ineligible for reelection to the Board. David Goulding is an incumbent trustee and expected to be re-nominated to serve another term. Vicky Bailey will not stand for re-election in 2013. The NERC Corporate Governance and Human Resources Committee (CGHRC) will review and consider the total number of trustees needed to serve on the Board, beginning February 2013. The tentative schedule for the 2013 elections includes: BOTNC Nomination Period Tuesday, September 4 – nomination period opens Monday, October 1 – nomination period closes The BOTNC also includes five members of the MRC:

• 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

Chair Helyer and Vice Chair Chinn invited MRC members to share questions or comments regarding the BOTNC, within one week, including any concerns with the re-nomination of Mr. Goulding.


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Remarks from Gerry Cauley, NERC President and CEO President Cauley welcomed participants to Quebec City and shared his appreciation for the MRC’s response to the Board’s request for policy input. He also recognized that the input highlighted several key issues and strategic challenges facing the ERO:

• Maturation of the NERC business planning and budget process (BP&B) – The ERO must continue to strive to improve its effectiveness, efficiency, and transparency through its business planning and budget process and through its delivery of results.

• Performance of key activities – The ERO must also understand why significant events occur on the bulk power system. Activities built around risk and event analysis, situational awareness, lessons learned, etc. assist the ERO in linking and connecting data and information to better understand events, determine causes, and formulate solutions.

• Impact of compliance – As the ERO prepares for the March 2013 filing of the Phase 2 Find, Fix, Track and Report (FFT) initiative, a comprehensive vision of an end-state for compliance enforcement should be developed. Attention has to be given to the existing culture of compliance and the ERO must also incent a shift that includes a culture of reliability. Effective internal controls, good monitoring procedures, and sampling of risk priorities are all pieces of a new compliance monitoring model that the ERO needs to consider and improve upon with input from the Regions, industry and FERC.

• Implementation of the Reliability Issues Steering Committee (RISC) – The RISC is designed to perform evidence-based prioritizing of real reliability issues to determine where to best allocate resources to achieve desired solutions. This new committee will work outside of the traditional mindset of incremental processes and timelines as it assists the ERO and industry in formulating solutions and resources towards improved reliability.

• Process improvements at NERC - There needs to be a formal process developed that determines how the ERO will prioritize and decide what resources and tools to allocate within the legal framework of Section 215.

NERC Business Planning and Budget Process Michael Walker, senior vice president and chief financial and administrative officer, NERC, reviewed the 2013 business planning and budget (BP&B) cycle and shared improvements for the 2014 cycle that include multi-year objectives and budget projections, earlier collaboration with the Regions and industry, and production of a common strategic plan. The following questions and comments were provided by the MRC regarding this topic:

• The 2013 business planning and budget process worked well and added transparency and predictability. NERC is commended for their cost control in the 2013 budget. NERC truly held to its 3-5 year commitment to level off resources.

• There was recognized consistency among the regional budgets and demonstration of greater coordination with NERC. The working relationship between NERC and the Regions gets stronger each year.


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• The policy input from the MRC highlighted the need to review NERC’s core activities. There is the potential for a lot of debate and dialogue regarding what constitutes NERC’s core activities. The MRC is asked to consider framing the debate to better define NERC core activities and priorities during a future meeting.

• Many are encouraged by this high level discussion among the Board and NERC staff to think differently, especially regarding the culture of reliability excellence. The Standards Process Input Group (SPIG) was a good beginning effort, but it did not go as far as it needed to go. There is still the need for a comprehensive plan with one complete vision for how the ERO gets industry pointed towards a culture of reliability excellence.

• MRC input remains beneficial and critical to NERC and the ERO’s business plan and budget. Chair Helyer proposed that the MRC focus more on defining the scope of the ERO and the culture of reliability excellence as well as provide assistance and input to NERC regarding the compliance initiative. Vice Chair Chinn and several other MRC members agreed to assist NERC staff with the future planning of the BP&B and with the preparations for the March 2013 FFT filing to FERC. Mr. Cauley clarified that there are two initiatives that will be best pursued through the development of two separate MRC subgroups:

1. Reaching an end-state of compliance assurance (culminating in the March 2013 FFT filing)

2. Providing input to the ERO BP&B process and documentation The following MRC members and participants agreed to support the two new subgroup efforts:

• Compliance Enforcement Initiative, March 2013 filing– John Seelke, Tom Bowe, Jeff Gust, and Jack Cashin

• BP&B, ERO scope - Bill Gallagher, John Anderson, Tom Burgess, and Mike Penstone Standards Process Input Group (SPIG) Recommendations Chair Helyer reviewed the initial five SPIG recommendations endorsed by the Board on May 8, 2012. In response to the SPIG’s Recommendation #2, on a motion by Bill Gallagher with a second by Terry Boston, the MRC endorsed the submission of the RISC charter to the Board for approval and the following initial slate of MRC and at-large member nominations for the RISC:

1. Scott Helyer, Tenaska, Inc. – Merchant Electricity Generator sector

2. Bob Schaffeld, Southern Company Services, Inc. – Investor-Owned Utility sector

3. Jason Marshall, ACES Power Marketing – Electricity Marketer sector

4. John Twitty, Transmission Access Policy Study Group – Transmission Dependent Utility sector

5. Brian Silverstein, Bonneville Power Administration– Federal/Provincial sector

6. Christine Schwab, Dominion – Investor-Owned Utility sector

7. Peter Flynn, National Grid – Investor-Owned Utility sector


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8. Mike Smith, Georgia Transmission Corporation – Cooperative Utility sector1

9. A vacancy for a Canadian Provincial representative, to be filled at a later date

Recommendation 2 The following questions and comments were provided by the MRC regarding Recommendation #2:

• There will not be a complete understanding of how the RISC will operate so the charter needs to remain broad through the committee’s initial formation.

• Membership of the RISC is intended to be broad and diverse, but the process by which to select the best candidates is still unclear. The SPIG’s nominating committee is encouraged to seek out the best candidates, through proactive dialogue, from each of the desired sectors and to include a Canadian representative.

• The one year review of the charter should also include thoughtful consideration for how issues and risks enter the committee’s review and consideration. An annual review may determine if additional activities should be submitted to the RISC in an effort to take the burden off of the SC.

• The RISC charter may also need a statement regarding the committee’s capability to review existing standards to determine the appropriate follow-on action, to include retirement of some standards.

• The Standards Committee (SC) process must continue and is not intended to stop and wait while the RISC is initiated. There must be work completed in parallel by both the SC and RISC, at least initially.

• The intent of the RISC seems to be providing guidance to ‘what’ enters the standards development process; however, it is still unclear whether all SARs will enter into the RISC. The processing of SARs makes a difference to the effectiveness of the RISC.

• Since standards are one of the outcomes of the RISC’s analysis, the issue regarding review of SARs is expected to be a two-way effort, determined on an as-needed basis. The RISC is expected to refer SARs to the standards committee and the standards committee is expected to send SARs to the RISC when it is believes that a broader solution is more beneficial than the development of a standard.

Chair Helyer confirmed that the RISC should be thought of, in a more general sense, as steering broader reliability issues and not just confined to reviewing SARs that go into the standards process. Notwithstanding that, there will be times when the RISC receives a SAR and determines that the best course of action or route for solution is through standards development. Chair Helyer also recognized that a lot can be learned from the current nomination process as the RISC matures, plans for future elections, and improves upon its own charter.

1 Mike Smith was proposed as an initial member of the RISC slate as part of an amended motion by Bill Gallagher.


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Mr. Cauley confirmed that the RISC is primarily intended to advise the board and set the reliability agenda for the ERO from a qualified and broad industry perspective. Recommendations 1, 3, 4 and 5 Regarding Recommendations 1, 3, 4 and 5, Herb Schrayshuen, vice president of standards and training, NERC, and Allen Mosher, chair of the Standards Committee, provided a brief update regarding changes to the Standard Processes Manual (SPM) and composition of the standard drafting teams (SDT) and the timeline of activities to strengthen relationships with governmental and provincial regulators. The following questions and comments were provided by the MRC regarding these additional SPIG recommendations:

• The approximate timeline for the implementation of these activities and process improvements is unclear. It is also unclear how the SC will utilize the wavier provision.

• When considering a schedule for engaging industry and governmental and provincial authorities in the process improvements, a 24-month look ahead is encouraged to better coincide with the planning and budget process. Events proposed to take place in 2012 are occurring after the approval of the 2013 budget.

• Project management of the process continues to be important and should include an understanding of the complexity of a standard being developed as well as a gauge for how soon it can be expected to be done or completed.

• The SC’s ability to waive any provision of the SPM, for a good cause, seems to be an overly broad waiver provision with little demonstrated need.

Mr. Mosher acknowledged that the SC will be cautious in the flexibility and use of a waiver provision. The use of a wavier will be publically disclosed to the Board. Mr. Cauley confirmed that intent of Recommendation #3 is to assist in formalizing ERO priorities in concert with industry and regulators. There are two annual events that are anticipated to promote this collaboration. One conference would occur in the fall to gather ideas/input and regulatory perspective to assist with prioritizing activities. The second event in the spring would promote a capstone report on activities and accomplishments that have occurred to-date. Status and Policy Input for Standards Projects The following updates were provided for several ongoing standards projects. Bulk Electric System (BES) Definition, Phase 2 Pete Heidrich, manager of reliability standards for Florida Reliability Coordinating Council, provided updates from the SDT assisting with the ERO’s response to FERC’s notice of proposed rulemaking (NOPR) issued in June 2012. A recent draft guidance document was developed to assist industry in identifying bulk electric system (BES) and non-BES elements, pending the final order that approves the BES definition. A technical justification project, under development with the Planning Committee and other subcommittees, is expected later this year or early next year to address the bright-line voltage criteria, generation and reactive resource thresholds, and power flow associated with local networks.


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The following comment was provided by the MRC regarding this topic:

• There is a need for a bright-line between BES and local distribution; however, this may not be the responsibility or job of this SDT.

Mr. Schrayshuen announced that the NOPR responses from NERC will be shared with the Trades and Industry in the upcoming days.

Definition of Adequate Level of Reliability (ALR) Mr. Mosher reported the recent posting of the revised definition of ALR for industry comment. The revised definition contains clarifying language for assessment objectives such as the identification of transmission and resource adequacy. Status of Communications Standards Mr. Schrayshuen provided an update on the status of the communications standards. During the February 2012 quarterly meetings, there were reservations raised regarding the completion of the communications standards and the filing of the COM-002 interpretation limiting required use of three-part communications to emergency situations. As a result, the interpretation was asked to be held until a more comprehensive package was available for the MRC and Board to consider. The elements of the comprehensive package include: an RSAW for COM-002, the standard development for COM-003, and a reliability guideline from the Operating Committee (OC). Mr. Cauley acknowledged the potential burden of documenting all instances of compliance with three-part communication. The comprehensive proposal is promoting a shift in the compliance burden philosophy by demonstrating that an effective communications program is underway and being checked for instances of noncompliance and where deficiencies are being identified and corrected. NERC and the Regions then have a role in checking the sufficiency and effectiveness of the program, the training of personnel, the sampling technique and that any findings or discoveries of noncompliance are being addressed. This new approach promotes learning opportunities and examples of incented performance and suggests a better way to test controls that are already in place to determine if they are or are not working properly. This approach also needs to be initiated for the upcoming CIP version 5 standards, which involves expanding cyber security on a prioritized basis among all bulk power system (BPS) assets. The potential burden of zero tolerance among all of these entities is too great when the focus is truly on implementing effective access controls that NERC can then check against for compliance purposes. The following comments were provided by the MRC regarding this topic:

• It is important that the same compliance principles be consistent across all versions of the CIP standards. NERC is encouraged to be aware of these inconsistencies throughout the development of version 5.

• Addressing zero defects is only half the equation in the CIP version 5 and the COM-003 standards; the other half of the equation is understanding how these standards will be audited.


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If we want to be successful with balloting, the industry needs to clearly understand how they are going to be audited against the new approach/language. Both standards have a high chance for success if the industry has a clearer understanding of the auditing approach that accompanies each.

• The industry is not solely concentrated on the zero defect issue surrounding three-part communication, but is largely concentrated on the impossibility for an operator to implement three-part communications during all circumstances. The standard should probably have not been balloted given this impossibility.

Mr. Cauley recognized that there will be exponentially more CIP violations under the current compliance model if the new approach is not implemented, but during this implementation there will be an effort to reach as much consistency across all standards as possible. Mr. Schrayshuen clarified, at the request of Janice Case, the balloting of COM-003 did not fail due to the implementation of the internal controls approach. Additional Discussion of the August 8 MRC Informational Session Items Chair Helyer asked for any additional discussion on the agenda items presented during the August 8 MRC Informational Webinar session. The following comments were provided by the MRC regarding the various topics discussed on August 8: Compliance Enforcement Initiative

• When will auditors or investigators make field determinations on FFT treatment?

• It is still unclear why minor administrative items, as part of the FFT process, take up to six months to track. What activity is occurring during each month or stage of FFT during this period of time?

Ken Lotterhos, associate general counsel and director of enforcement, confirmed that field auditors and investigators can presently make recommendations to the CEA enforcement staff. In parallel, NERC and the Regions are developing a whitepaper to address the future of CEI as well as field determinations and pilot efforts for early 2013. Mr. Lotterhos also noted the ongoing collaborative effort among NERC, the Regional Entities and registered entities to improve upon the current processing time for FFTs. Lack of prequalification and completion of mitigation plans by entities has contributed to slower processing times in the past. 2012 Emerging Issues Survey for Long-Term Reliability Assessment

• The survey poll indicates that there should be more focus on gas-electric interdependency with the increased build out expected over the next few years.


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• Cyber security may not be considered an emerging issue since there is ongoing focus in this area, but it may need to remain on the list if specific cyber risk-based tools need to be developed or become available at some future point.

• Environmental regulation is questioned on the list since it is more concentrated on costs than on risk to reliability.

• The three risks/issues of primary concern are driven by environmental-based concerns to some degree, but climate change does not seem to appear on the list.

Mr. John Moura, associate director of reliability assessment, NERC, confirmed that topics, such as climate control, can be recommended annually for consideration and further review or special assessment. Mr. Cauley recognized that these emerging reliability issues have merit and challenges. The RISC will be asked to weigh risks that may not be seen as frequent. Despite that a framework is already in place for prioritizing low frequency, high impact issues through raw data, event analysis and opinion surveys, better methods may be needed for developing and quantifying a full risk portfolio. Report on Rules of Procedure Process Improvements Rebecca Michael, associate general counsel, NERC announced that a NERC staff report will be shared with the Board, on August 16, that includes improvements and enhancements to the processes used to revise the Rules of Procedure (ROP). The following four key enhancements were developed in response to comments provided during the last ROP revisions: more transparency, earlier engagement with industry and Regions, additional information shared during the actual changes to the ROP, and the ability to maintain flexibility and take additional time when warranted. Follow-up Activities from the 2011 Southwest Outage Dave Nevius, senior vice president, NERC, and Melanie Frye, vice president of operations and planning, for Western Electricity Coordinating Council (WECC), provided a status and progress update, from WECC and the other Regional Entities, in response to the findings and recommendations of the FERC/NERC Inquiry. WECC recently initiated a survey of the operating practices in the Western Interconnection that focused on identifying successes, gaps and challenges in the following areas: next-day studies, seasonal planning, near and long-term planning, situational awareness, consideration of BPS equipment, protection systems, and angular separation. A final report, expected later this month, will address WECC’s progress in response to NERC’s July 26, 2012 request and timeline for completing remaining remediation efforts. November 6, 2012 Meeting and Future Meetings

The following are future MRC meeting dates and locations:

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

• February 6–7, 2013 – San Diego, CA

• May 8–9, 2013 – Philadelphia, PA


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• 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 Charlie Berardesco, senior vice president and general counsel, NERC, at the conclusion of the meeting. Adjournment There being no further business, the meeting terminated at 5:00p.m. local time. Submitted by,

Holly Mann Secretary

Agenda Item 2 MRC Meeting November 6, 2012

Future Meetings

Action Reference change in location from Philadelphia, PA to Boston, MA for the May 8-9, 2013 meetings. Summary The below are the future meetings as approved by the board on May 11, 2011. 2013 Dates

February 6-7 San Diego, CA

May 8-9 Boston, MA

August 14-15 Montreal, Canada

November 6-7 Atlanta, GA

2014 Dates

February 5-6 Phoenix, AZ

Agenda Item 3a MRC Meeting November 6, 2012

Election of MRC Officers for 2013 and Sector Elections Action Elect Officers for 2013. Background Article VIII, Section 5 of the NERC Bylaws addresses election of the Chair and Vice Chair of the Member Representatives Committee. Article VIII states:

Section 5 — Officers of the Member Representatives Committee — At the initial meeting of the Member Representatives Committee, and annually thereafter prior to the annual election of representatives to the Member Representatives Committee, the Member Representatives Committee shall select a chairman and vice chairman from among its voting members by majority vote of the members of the Member Representatives Committee to serve as chairman and vice chairman of the Member Representatives Committee during the upcoming year; provided, that the incumbent chairman and vice chairman shall not vote or otherwise participate in the selection of the incoming chairman and vice‐chairman. The newly selected chairman and vice chairman shall not have been representatives of the same sector. Selection of the chairman and vice chairman shall not be subject to approval of the board. The chairman and vice chairman, upon assuming such positions, shall cease to act as representatives of the sectors that elected them as representatives to the Member Representatives Committee and shall thereafter be responsible for acting in the best interests of the members as a whole.

The nominating period for the two officer positions of the Member Representatives Committee for 2013 opened on August 31, 2012 for a 30‐day nominating period that closed October 1, 2012. The election of officers at this meeting and the current nomination period for sector members for 2013–2014 provides for filling sector vacancies resulting from a member being elected to an officer position. The nominating period for sector members continues through November 13, 2012. The nominees for MRC Chair and Vice Chair for 2013 are: Chair – Carol Chinn Vice Chair – John Anderson

Agenda Item 3b MRC Meeting November 6, 2012

Update on MRC Sector Nominations and Election

Action None Background Chair Scott Helyer will remind members of the current sector nomination period for those representatives whose terms expire in February 2013. The nomination period opened on September 10, 2012 and will close November 13, 2012. Sector elections are scheduled to begin December 3, 2012 and end December 14, 2012. 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

Agenda Item 3c MRC Meeting November 6, 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 the MRC Chair and Vice Chair on the Nominating Committee; and those members are 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 The period for submissions of potential Trustee nominees ended October 1, 2012. Board Nominating Committee Chair, Jan Schori, will provide a status report on the planned activities and schedule for the Committee.

Agenda Item 5a MRC Meeting November 6, 2012

Standards Process Reform Action Information Background NERC, the Regional Entities and industry stakeholders have a significant mutual investment in developing a sustainable Reliability Standards program that will maintain the reliability of the bulk power system in North America. The Electric Reliability Organization (ERO) is responsible for the development of a body of clear, high quality, technically excellent Reliability Standards that are needed to ensure the reliable operation and planning of the bulk power system, and the NERC Board of Trustees (Board) is responsible for establishing strategic priorities for NERC, including ensuring that this responsibility is carried out in a timely and efficient manner that meets regulatory obligations. Further, the ERO relies on the technical expertise and commitment of industry volunteers to develop technically excellent Reliability Standards based on the principles of an ANSI-accredited standards development process to ensure industry consensus in support of these standards. The success of the unique ERO model requires NERC to develop and maintain a body of high-quality, effective Reliability Standards. However, the current trajectory is unsustainable and, without considering significant course correction, the ERO and industry finds itself nearing a critical juncture where alternate methods to accomplish the development of mandatory Reliability Standards has become necessary. The NERC Board foresaw this juncture and has called for change that has not resulted in enough significant improvement. In response, NERC staff and the Member Representatives Committee’s Standards Process Input Group present a request for the NERC Board to approve the attached resolutions. The resolutions call for a series of actions with a report on results to be provided to the Board at its February 2013 meeting. A supporting paper is provided with additional information on the resolutions. Enclosed Attachments

1. Proposed Board Resolutions – Improvements to the Reliability Standards Development Process

2. Supporting proposal – Establishing a Sustainable ERO Standards Model If you have questions or need additional information, please contact Vice President and Director of Standards Mark Lauby at [email protected].

mailto:[email protected]�

NORTH AMERICAN ELECTRIC RELIABILITY CORPORATION

Proposed Resolution for Agenda Item __: Improvements to the Reliability Standards Development Process

Board of Trustees Meeting

November 7, 2012 WHEREAS, the Electric Reliability Organization (ERO) is responsible for the development of a body of clear, high quality technically excellent Reliability Standards that are needed to ensure the reliable operation and planning of the bulk power system. WHEREAS, the NERC Board is responsible for establishing strategic priorities for NERC, including ensuring that this responsibility is carried out in a timely and efficient manner that meets regulatory obligations. WHEREAS, the ERO relies on the technical expertise and commitment of industry volunteers to develop technically excellent Reliability Standards based on the principles of an ANSI-accredited standards development process to ensure industry consensus in support of these standards. WHEREAS, the ERO relies upon and has delegated responsibility to oversee and manage the standards development process to the Standards Committee, and the Standards Committee appoints the standard drafting teams that are charged with executing these responsibilities. WHEREAS, NERC, the Regional Entities and industry stakeholders have a significant mutual investment in developing a sustainable Reliability Standards program that will maintain the reliability of the bulk power system in North America. WHEREAS, the Standards Committee and standard development teams should be accountable to the Board for developing and maintaining high quality standards in a timely manner and further enabling the ERO to respond to reliability priorities. WHEREAS, on May 9, 2012, the Board endorsed the recommendations of the Standards Process Input Group for improving the effectiveness and efficiency of the NERC standards development process. WHEREAS, the institution of the Reliability Issues Steering Committee was approved as a Standards Process Input Group recommendation by the Board to advise the Board on prioritization and dispensation of Reliability Standards efforts. WHEREAS, in response to these recommendations, the Standards Committee developed proposed revisions to the Standard Processes Manual, which is set forth as Appendix 3A to the NERC Rules of Procedure, that are expected to be presented to the Board for approval in February 2013.

WHEREAS, NERC, the Regional Entities, and stakeholders are nearing a critical juncture where alternate methods to accomplish the development of mandatory Reliability Standards have become necessary. WHEREAS, NERC and the Standards Committee have determined that establishing a body of high-quality Reliability Standards will require dispensing of work that is no longer pertinent to reliability, and aggressively pursuing work that will result in a body of high-quality Reliability Standards that will address reliability risks to the bulk power system. WHEREAS, the ERO is in full accord with industry stakeholders that fundamental changes to the NERC compliance and enforcement process are required to ensure that perceived enforcement risks do not have an adverse impact on the development of high quality Reliability Standards. WHEREAS, NERC management has committed to make available the NERC resources and processes needed to execute this plan.

NOW, THEREFORE, BE IT RESOLVED, that the ERO must move forward to develop a body of high-quality results-based standards. FURTHER RESOLVED, that the Standards Committee and standard development teams should be accountable to the Board while developing and maintaining high-quality Reliability Standards in a timely manner and further enabling the ERO to respond to reliability priorities, and the Standards Committee shall modify its governance, structure and scope to enable such accountability. FURTHER RESOLVED, that standard drafting teams should be staffed with a small number of subject matter experts that includes competencies in technical, legal, drafting, compliance, and project management. FURTHER RESOLVED, that the Standards Committee should manage workflow and process to ensure the timely development of high-quality, results-based Reliability Standards. FURTHER RESOLVED, that the Standards Committee and NERC staff should work with the Reliability Issues Steering Committee to jointly develop viable work plans to dispense with work that is no longer pertinent to reliability and aggressively pursue work that will result in a body of high-quality Reliability Standards that will address reliability risks to the bulk power system. FURTHER RESOLVED, that the Standards Committee and NERC staff is hereby directed to report back to the Board at the February 2013 meeting on the status of these directives.

Establishing a Sustainable ERO Standards Model October 2012

The Electric Reliability Organization (ERO) is responsible for the development of a body of clear, high quality, technically excellent Reliability Standards that are needed to ensure the reliable operation and planning of the bulk power system, and the NERC Board of Trustees (Board) is responsible for establishing strategic priorities for NERC, including ensuring that this responsibility is carried out in a timely and efficient manner that meets regulatory obligations. Further, the ERO relies on the technical expertise and commitment of industry volunteers to develop technically excellent Reliability Standards based on the principles of an ANSI-accredited standards development process to ensure industry consensus in support of these standards.

NERC, the Regional Entities and industry stakeholders have a significant mutual investment in developing a sustainable Reliability Standards program that will maintain the reliability of the bulk power system in North America. The success of the unique Electric Reliability Organization (ERO) model requires NERC to develop and maintain a body of high-quality, effective Reliability Standards. The current trajectory is unsustainable and, without considering significant course correction, the ERO and industry finds itself nearing a critical juncture where alternate methods to accomplish the development of mandatory Reliability Standards has become necessary. NERC is at risk of losing the confidence of U.S. regulatory authorities and industry executives in its ability to produce standards in a timely and efficient manner. The NERC Board foresaw this juncture and has called for change that has not resulted in enough significant improvement. The ERO and industry must seize this opportunity to reform its standards program to achieve an endstate that is defined by a set of high quality standards that are created using the technical expertise of industry and that support the reliability of the bulk power system. Additionally, the endstate must provide clear compliance expectations and predictable, consistent compliance assessment. Although the current approach to developing standards has been identified by various stakeholders, the NERC Board, and regulators as flawed, the standard development process itself is not the primary impediment to the production of standards. Some of the current challenges are:

1. To make the ERO model sustainable, there needs to be a chain of accountability of the Standards Committee (SC) to the NERC Board that is in addition to SC members having accountability to the ballot body, their respective organizations, and industry segments. There is a need to refocus the SC on its obligation to support the reliability goals and priorities established by the NERC Board for the ERO.

2. The technical foundation for new projects must be clear and widely agreed upon before standards projects are initiated.

Establishing a Sustainable ERO Model – October 2012 2

3. There needs to be a comprehensive strategy to address outstanding reliability directives and recommendations from the 2003 Blackout Report, NERC’s five-year standard review obligation, continuing efforts for Paragraph 81 as well as completion of on-going and emerging issue projects.

4. NERC and the SC need to staff standard development teams with a smaller number of industry experts to facilitate greater efficiency in developing sound standards. Experience has demonstrated that the appointment of larger teams, which is a consequence of diverse representation, can lead to certain inefficiencies.

5. Reliability Standards need to be developed without regard to compliance risk management which will require a change in philosophy for those who are developing the standards, as well as a change in compliance enforcement methods and philosophy.

6. Trust needs to be improved between NERC and Regional Entity staff and stakeholders. NERC staff recognizes these challenges and recently made substantial organizational changes to support standards development:

1. Leadership and staff changes. The leadership change brings new perspectives and fresh ideas to the various departments as well as promoting interdepartmental coordination. Staff changes in the Standards Department, in particular, have refocused staff from 60 percent dedicated to process to 80-90 percent dedicated to production.

2. Addressing Compliance. NERC staff is redefining the endstate of compliance by: (1) refocusing audits from checklist to be more strategic/tactical with emphasis on risk control and mitigation; (2) reviewing records maintenance to determine the necessary amount of documentation to demonstrate compliance; (3) clarifying the applicable enforcement process when possible non-compliance is identified; and (4) introducing proper incentives and strategies in enforcement.

3. Standing up RISC. This committee will facilitate a proactive identification and prioritization of high risk reliability issues and enable the ERO to preemptively address related risks to ensure reliability. There is urgency for the RISC to develop a standing portfolio of prioritized risks.

NERC is requesting industry to rally and work hand-in-hand in a way that allows the ERO to develop a strategic, proactive approach to creating fully developed standards, rather than reactively responding, for example, to FERC directives. This is an opportunity for everyone to work together with the goal of developing comprehensive, high quality standards using industry expertise. This requires assessing the current status of the body of standards and identifying the end point to be achieved, defined in terms of a world-class product, not a process. Request for NERC Board Resolution and Actions NERC Staff and the Member Representatives Committee (MRC), along with the Standards Process Input Group (SPIG), request the NERC Board to issue the attached resolution. The background information in this paper is intended to provide guidance for consideration by the SC in its implementation of the Board’s resolutions.


Accountability in NERC Standards Development Resolution: Standards Committee and standard development teams are to be accountable to the NERC Board while developing and maintaining high-quality standards in a timely manner and further enabling the ERO to respond to reliability priorities, and the Standards Committee shall modify its governance, structure and scope to enable such accountability. Supporting Information: The SC should review and, as necessary, modify the Committee’s governance, structure and scope to ensure SC accountability to the NERC Board for the creation and maintenance of a high quality body of standards that supports the reliability of the bulk power system. This could include modifying the SC governance documents to facilitate the NERC Board’s oversight of SC leadership and membership, accountability to the NERC Board for the production and maintenance of the NERC body of standards, and for oversight of the process, which is defined as a high level oversight to monitor production, noting exceptions to the process, but not day-to-day operational control. The NERC Board could assume its authority under the Rules of Procedure to appoint the SC Chair and Vice Chair.1

Further, SC governance documents could be modified to show that SC members will be elected for a maximum of two consecutive terms, unless there are no alternative candidates available, subject to a final review and endorsement of each of the officers by the NERC Board. Additionally the NERC Board could ratify re-election of members on the SC roster, based on the individual’s performance during the prior term.

Finally, the SC should consider reviewing its governance to include a recommendation to address the SC voting model to enable decision making. The SC is to present its results to the NERC Board at the February meeting. Objective: The SC should be accountable to the NERC Board for the production and maintenance of the NERC body of standards that are based on the eight reliability principles and a technical foundation that supports reliability of the bulk power system, and for oversight of the process, which is defined as a high level oversight to monitor production, noting exceptions to the process, but not day to day operational control. The SC should also prohibit the use of its structure and authority, by members or observers, to hedge compliance risk. Resourcing Standards Development Teams for Success Resolution: Standard drafting teams are to be staffed with a small number of subject matter experts that includes competencies in technical, legal, drafting, compliance, and project management. Supporting Information: The SC, pursuant to its restructured governance and scope, should modify how drafting teams are staffed to include people that have the required knowledge and technical competencies necessary to create the applicable standard assigned to them in a timely manner. Specifically, the SC should create small, agile standards development teams made up of subject matter experts that include the following competencies: technical, legal, drafting, compliance, and project management. 1 Under section 1303 of the Rules of Procedure the Board has the authority to approve NERC standing committee member appointments and appoint committee officers.


The SC should select drafting team members that have the willingness and ability to devote the time and effort necessary to meet the project schedule. Objective: The SC should consider staffing small, efficient drafting teams based on each individual’s knowledge and technical competencies needed to develop standard. Work Flow Management Resolution: Standards Committee is to manage workflow and process to ensure the timely development of high-quality, Results-Based Reliability Standards. Supporting Information:

1. The RISC2

• Prioritizing, for NERC Board approval, high level reliability issues;

should recommend a clear direction to the NERC Board and SC regarding the need for the development of a standard, which could include the following:

• Performing triage on incoming issues, including requesting technical analysis from NERC Committees, to determine if action is needed;

• If action is needed, determining what form of resolution should be conducted (creation of a standard, guideline, alert or other);

• If a standard is needed, ensuring the Standards Authorization Request (SAR) provides a sufficiently clear problem definition and necessary technical research to enable the drafting team to develop a standard; and

• Sending a SAR to SC and NERC staff for production.

2. The SC should manage drafting teams’ workflow to produce high quality standards and timely completion of work projects, including consideration of the following:

• Directing drafting teams to expedite activities within the process; Focusing drafting team meetings on tasks necessary for production and not on group editing of documents or other tasks that could be accomplished between meetings;

• After initial interviews of subject matter experts, developing a draft prior to the next meeting; and

• Using informal methods to obtain early consensus prior to formal commenting and balloting.

2 The RISC’s charter provides: 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. [emphasis added]


Objective: The RISC should consider determining which issues are related to identified high risk reliability issues (with NERC Board approval) and therefore should be addressed, and in what manner the issue is to be addressed (standard, guideline, alert or other manner). Drafting teams could then develop standards using an efficient workflow process, based on the need of the project. Work Plan Resolution: Standards Committee and NERC staff are to jointly develop viable work plans to dispense with work that is no longer pertinent to reliability and aggressively pursue work that will result in a body of high-quality Reliability Standards that will address reliability risks to the bulk power system. Supporting Information: The SC and NERC staff should jointly develop a work plan and schedule by the end of 2012 that will achieve the endstate of having a body of high quality standards. The coordinated work plan could collectively address:

1. Resolving outstanding FERC Directives and August 14, 2003 Blackout Recommendations;

a. Directives and recommendations could be reviewed to determine whether they are still relevant or have been overtaken by events and are no longer needed.

2. The review and updating of all current standards to be world-class, which will:

a. Evaluate what requirements are no longer necessary and retire them (Paragraph 81 Phase II);

b. Update the construct of the standards to the “results-based standards” format; and

c. Concurrently develop the compliance assessment information in parallel with the review and update of each standard. This is to be done in conjunction with the Compliance and Enforcement departments of NERC and the Regional Entities.

3. Prioritize and complete current, proposed and emerging issue projects. Objective: The ERO should maintain a body of high-quality, results-based standards that support the reliability of the bulk power system that is responsive to changes to the system, including emerging issues.

Summary The requested NERC Board resolution will facilitate a united effort between the SPIG, the MRC, the SC, NERC staff and industry stakeholders to reform its standards program to achieve an endstate that is defined by a set of high quality standards that are created using the technical expertise of industry and that support the reliability of the bulk power system.

Agenda Item 5b MRC Meeting November 6, 2012

Compliance Enforcement Initiative Update

Action Discussion Background During the August 15, 2012 Member Representatives Committee (MRC) meeting, dialogue pertaining to a desired endstate of compliance for a mature ERO was shared as well as the outputs and activities that would support the overall initiative. The activities include the drafting of a White Paper1

describing the desired endstate attributes as well as the change state elements necessary to achieve the desired attributes.

Summary Since August 15 meeting, the White Paper has been drafted, key change state elements defined, and deliverables for both the filing and the achievement of the endstate developed. In this regard, these elements will be presented for discussion, and including the outline of the next steps to support the efforts leading up to the proposed March 2013 filing with FERC. Key elements that will be discussed during the November 6, 2012 meeting include:

• White Paper

The need for a change to the compliance approach

The use of risk based approaches for the scoping of engagements

Designing tests of controls to evaluate compliance

The use of auditor discretion

The effective use of enforcement

• Change State Elements

Restyling the overall compliance monitoring approach

Evaluating data retention requirements in support of compliance

The flow of information from compliance

• The redesign of the enforcement strategy

• Deliverables

Actions pertaining to the March filing and planned distribution of materials for feedback

Activities related to the design of a pilot effort and anticipated implementation

1 The whitepaper that accompanies the MRC agenda package is considered a preliminary draft for discussion purposes only. The concepts and details within the paper continue to be refined based on the input that NERC receives from the Regions, the MRC CEI Input Group, the Trades, and other valuable stakeholders. The draft whitepaper is being released at this time to assist the MRC in formulating their responses to the NERC board’s request for policy input.

Short-range activities to facilitate near term changes

Long-range activities for the full implementation of the change elements Enclosed Attachments

1. Summary of the remaining milestone deliverables (November 2012 –March 2013)

2. Draft conceptual White Paper: Incorporating Risk Concepts into the Implementation of Section 215

Agenda Item 5b Attachment 1 MRC Meeting November 6, 2012

Compliance Enforcement Initiative – Milestone Deliverables

Activity Deliverable Date

Present Conceptual Paper and Key Change State Elements to the ERO Executive Management Group (NERC and the Regions)

November 5, 2012

Conceptual Paper – Restyling Audit November 26, 2012

Conceptual Paper – Information Flow December 10, 2012

Conceptual Paper – Record Retention January 7, 2013

Conceptual Paper – Enforcement Strategy

January 21, 2013

Conceptual Paper – Pilot Program February 4, 2013

Draft Filing Release February 18, 2013

Filing March 15, 2013

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Incorporating Risk Concepts into the Implementation of Compliance and Enforcement

Table of Contents

I. Introduction and The Need for Change II. The Proposed Changes Promote BES Reliability III. Effective Regulation Uses Risk-Based Concepts IV. The End State of the Compliance Monitoring and Enforcement Program

A. Transition to Compliance Monitoring Based on Risk B. Transition to Prioritizing and Treating Violations in Accordance with their Risk C. Transition to Utilizing Compliance Monitoring and Enforcement to Send

Meaningful Signals Based on Risk D. Transition to Reliability Standards Based on Risk

V. Next Steps: Implementing Risk-Based Concepts VI. Conclusion

2

Incorporating Risk Concepts into the Implementation of Compliance and Enforcement

I. Introduction and The Need for Change

The Energy Policy Act of 2005 (the Act) created a reliability framework that includes the Federal Energy Regulatory Commission (FERC or the Commission), the Electric Reliability Organization (ERO) (designated as the North American Reliability Corporation (NERC)), and eight Regional Entities (NERC and the Regional Entities, collectively referred to as the ERO Enterprise) with thousands of stakeholders and nearly 2000 entities subject to the ERO’s rules. Three of the primary responsibilities outlined by the Act are developing standards, promoting and monitoring compliance with those standards and enforcing acts of non-compliance with the standards – all with the overarching objective of avoiding cascading events and the resulting major loss of load.

Compliance and enforcement of the standards was delegated to the eight Regional Entities, subject to oversight by NERC and FERC. This responsibility came with the requirement and expectation that every violation, regardless of risk, be prosecuted. Violations came with the prospect of significant monetary penalties for noncompliance. This “zero tolerance” application of compliance and monitoring without regard to the risk to the bulk electric system (BES) has unduly focused attention and resources on compliance risk and administrative processes as opposed to reliability risk.

Over the last five years’ through experience with the compliance and enforcement processes and feedback from stakeholders, the ERO Enterprise1 has envisioned an end state that is founded on a risk-based approach. This vision will be developed through maturing the ERO Enterprise processes over the next three to five years and be tested through a pilot project as we reach full implementation2

1 ERO Enterprise refers to NERC and the eight Regional Entities.

. It is not practical, effective or sustainable for the ERO Enterprise and Registered Entities to monitor and control all compliance to the same degree. Further, it is not practical, effective, nor sustainable for the ERO Enterprise and Registered Entities to treat all findings and discrepancies, as violations triggering the same degree of enforcement and evidentiary documentation. Where a violation does not pose a serious or higher risk to the reliability of the bulk power system, and the Registered Entity has a compliance program and internal controls that detect, assess, mitigates and self-reports the violation, the Regional Entity may decline to pursue and enforcement action.

2 The end-state envisioned will be developed over time, in part through pilot projects and the measured implementation of activities, tools and processes.

3

The risk-based approach the ERO Enterprise envisions will consider risk relative to the tools and processes applied to assure compliance as well as the disposition of instances of noncompliance incorporate risk concepts. To this end, the future risk-based approach of the CMEP will be a consistent (ERO Enterprise-wide) application of (A) compliance monitoring practices based on risk, (B) a “range of tools”3 to prioritize and treat violations based on risk, (C) enforcement practices with clear distinctions based on risk to reliability and (D) a strengthened feedback loop from compliance monitoring and enforcement to the standards development process to incorporate considerations of actual risk into the standards development process.4

This white paper discusses the end state envisioned as well as the benefits associated with incorporating risk management practices into the CMEP work and linking it to the standards development process through a feedback loop. Throughout the course of the whitepaper, the need and the basis for changing the compliance monitoring and enforcement work of the ERO Enterprise is established; the framework for changes to the compliance monitoring and enforcement work is presented; and the next steps to define the path forward and related activities are outlined. The changed state contemplated by this whitepaper is intended to be the basis for an informational filing by NERC with the Commission in March 2013.

This overall risk-informed end state will guide Registered Entities to be increasingly focused on reliability and toward self-critical corrective actions resulting in continuous contribution toward real reliability, rather than the current model. At the same time, the current enforcement and penalty model will be used for higher risk or serious violations.

II. The Proposed Changes Promote BES Reliability

The North American electric grid operating in real time is the world's most complex transmission system; in this regard, reliability risk is neither uniform across the grid nor constant over time, but is complex and interdependent. Assuring the reliability of this system requires understanding the risks that may impact its function and developing the controls to

3 See Malcolm K. Sparrow, The Regulatory Craft, 100 (2000). Sparrow advocates using a “range of tools for procuring compliance and eliminating risks ….” Our existing rules of procedure together with foundational documents referenced in the rules of procedure, such as the Yellow Book Government Audit Standards provide a range of tools which can be scoped and deployed based on risk. Those tools include audits, spot checks, data submittals and self-certifications. These tools, together with the ability of the Regional Entity to decline to enforce a violation, comprise a full “range of tools.” 4 These concepts will be implemented by (1) restyling the ERO’s overall compliance approach to conform to well-established audit principles as described herein including the right to decline to pursue violations across the ERO Enterprise; (2) establishing the requirements for Regional Entity’s records to facilitate NERC and FERC oversight; (3) establishing processes for information flow between compliance functions and enforcement functions as well as an open, transparent and clear approach as to which matters will be subject to enforcement procedures; and (4) redesigning the enforcement strategy to focus on serious or higher risks to the BES.

4

discover and mitigate those risks. Ultimately it is this proactive, risk-based approach that will allow the ERO Enterprise to provide reasonable assurance of current and future BES reliability.5

The end-state vision of a sound risk-based reliability approach will reflect principles that form the foundation for focus and prioritization, as well as recognition of the core elements that ensure reliability of the bulk electric system. In this end-state vision, the compliance, enforcement and standards elements form an integrated structure with focus on the priorities that most influence reliability. The alignment of processes, systems and resources will ensure the proper attention to those reliability matters. Lesser and more minor matters are considered and addressed in a far simpler fashion which encourages the documentation of internal self-corrective activities that diminish the potential for the accumulation of minor unaddressed matters.

The ERO must abandon “zero tolerance” compliance monitoring and enforcement because:

• The pursuit of all violations without regard to risk or administrative burden is neither effective nor sustainable.

• The focus has become documenting compliance, not reducing risk and improving reliability.

• Enforcement considers a historic state of reliability, not the current or future state of reliability.

• Improvements to processes, such as the administrative citation process or find, fix, track and report, reduce the ERO’s administrative burden, but do not have commensurate impact on improving reliability and reducing industry’s administrative burdens.

Therefore, to encourage and reward proactive self-assessment the ERO Enterprise should use a “full range of tools6

” to shape compliance, monitoring and enforcement based on risk. The incorporation of risk management concepts into the ERO’s work, from standards development to compliance monitoring and enforcement, will encourage compliance and risk mitigation.

5 Former FERC Commissioner and Chairman Joseph T. Kelliher stated: “The Energy Policy Act of 2005 did not outlaw blackouts and the reliability provisions of section 215 do not promise perfect reliability at any price.” See, Remarks of the Honorable Joseph T. Kelliher, Executive Vice President – Federal Regulatory Affairs, FPL Group, Inc., Reliability Primer for Lawyers and Energy Professionals, Energy Bar Association, 6,7 (April 28, 2010), http://utilitysvcs.info/docs/Kelliher%20NERC%20speech.pdf 6 A full “range of tools” includes the ability to decline to pursue a violation. See also note 2, supra.

http://utilitysvcs.info/docs/Kelliher%20NERC%20speech.pdf�

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III. Effective Regulation Uses Risk-Based Concepts

Moving from zero tolerance to a risk management approach requires a different way of assessing reliability concerns. Dr. Malcolm K. Sparrow advocates that regulators use a risk-based “problem solving” approach which he describes in his book, The Regulatory Craft7

systemic identification of important hazards, risks, or patterns of noncompliance; an emphasis on risk assessment and prioritization as a … basis for resource allocation decisions … capacity for designing and implementing effective, creative, tailor-made solutions for each identified problem; the use of a range of tools for procuring compliance and eliminating risks; and the recognition of the need to retain and enhance the agency’s enforcement ‘sting’ while using enforcement actions economically and with the context of coherent compliance strategies.

, as the:

8

The ERO Enterprise will adopt a “problem solving” approach that incorporates risk-based practices into its work, similar to other regulatory bodies with compliance and enforcement responsibilities. This approach will increase BES reliability and ERO Enterprise efficiency and effectiveness. The following describes how other U.S. Federal entities use a risk-based problem solving approach.

Many US federal agencies responsible for compliance and enforcement utilize risk management practices. The Securities and Exchange Commission (SEC)9, the Environmental Protection Agency (EPA)10, and the Occupational Safety and Health Administration (OSHA)11

7 See Sparrow, supra note 1.

all have

8 Id. 9 In “Compliance Programs, Penalty Mitigation and the FERC” former FERC General Counsel and Chief of Staff John Moot cites an SEC action forgoing enforcement because “the company had quickly identified the violations, promptly reported them, remedied them internally through disciplinary actions, and taken prospective corrective action to avoid future violations.” See, John C. Moot, Compliance Programs, Penalty Mitigation and the FERC, 29 Energy Law Journal 547, 562-563 (2008). 10 The EPA’s policy on Incentives for Self-Policing, Discovery, Disclosure, Correction and Prevention of Violations provides: “The revised Policy … is designed to encourage greater compliance with Federal laws and regulations that protect human health and the environment. It promotes a higher standard of self-policing by waiving gravity-based penalties for violations that are promptly disclosed and corrected, and which were discovered systematically-that is, through voluntary audits or compliance management systems.” See, Environmental Protection Agency, Incentives for Self-Policing: Discovery, Disclosure, Correction and Prevention of Violations, 65 Fed. Reg. 19,618 (2000), http://www.epa.gov/oecaerth/resources/policies/incentives/auditing/auditpolicy51100.pdf cited by Moot, supra note 8 at 564-65. 11OSHA’s “star” status program also seeks to improve safety and health outside of enforcement. Under the “star” program, OSHA can exempt employers from routine inspections and allow them to claim “star” status in exchange for maintaining exemplary safety records and satisfying other program certification requirements. The pursuit of “star” status improves employee safety and health, decreases regulatory costs and enhances an entity’s

http://www.epa.gov/oecaerth/resources/policies/incentives/auditing/auditpolicy51100.pdf�

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policies, programs and discretion to encourage compliance and allow the agency to decline to pursue a violation based on the particular set of circumstances and facts.12 Companies subject to regulations are encouraged to be self-policing “because government resources are limited, universal compliance cannot be achieved without active efforts by the regulated community to police themselves.”13

FERC’s processes provide “great flexibility in fashioning the most appropriate and effective remedies and sanctions for each violation….” This includes the ability to decline to pursue an enforcement matter. In its Revised Policy Statement on Enforcement

14 the Commission stated “between 2005 and 2007, Enforcement staff closed approximately 75% of its investigations without any sanctions being imposed, even though Enforcement staff found a violation in about half of those closed investigations.”15

Risk-based concepts are clearly contemplated in NERC’s Rules of Procedure Appendix 4C - Compliance Monitoring and Enforcement Program which provides: “Compliance Audit process conducted in the United States shall be based on professional auditing standards recognized in the U.S. including Generally Accepted Auditing Standards, Generally Accepted Government Auditing Standards, and standards sanctioned by the Institute of Internal Auditors.”

16 These professional standards are well-established and well-accepted. They provide a principled basis for conducting the ERO’s compliance monitoring work in a consistent manner and they incorporate risk-based concepts. For example, the Generally Accepted Government Auditing Standards (GAGAS) “provide a framework for conducting high quality audits with competence, integrity, objectivity and independence.”17

reputation. See Orly Lobel, Interlocking Regulatory and Industrial Relations: The Governance of Workplace Safety, 57 ADMIN. L. REV. 1071, 1105-08 (2005).

“GAGAS contains requirements and guidance

12 See, John C. Moot, Compliance Programs, Penalty Mitigation and the FERC, 29 Energy Law Journal 547(2008). 13 See, Environmental Protection Agency, Incentives for Self-Policing: Discovery, Disclosure, Correction and Prevention of Violations, 65 Fed. Reg. 19,618 (2000), http://www.epa.gov/oecaerth/resources/policies/incentives/auditing/auditpolicy51100.pdf cited by Moot, supra note 8 at 564-65. 14 See Revised Policy Statement on Enforcement, 123 FERC ¶ 61,156 (2008). 15 Id. at P 9. For examples of self-reports and investigations closed with no action, see 2011 Report on Enforcement Prepared by the Staff of the Office of Enforcement, Federal Energy Regulatory Commission (November 17, 2011), http://www.ferc.gov/legal/staff-reports/11-17-11-enforcement.pdf. 16 See GAO Government Audit Standards (December 1, 2011), 6.05, 6.16-6.22, 5.44(b.), citing Institute of Internal Auditors (IIA) International Standards for the Professional Practice of Internal Auditing. Chapter 6 “Field Work Standard for Performance Audits” provides an existing guide. For example, “adequacy of the audited entity’s systems and processes to detect significant errors” is a factor affecting audit risk. The “nature, timing or extent” of the audit may be altered based on the auditor’s assessment of internal controls. Similarly, the Institute of Internal Auditors (IIA) International Professional Practices Framework Performance standard 2130 – Control requires that the internal audit function “evaluate the adequacy and effectiveness of controls…” These themes are also common in American Institute of Certified Public Accountants (AICPA) Generally Accepted Auditing Standards (GAAS) – Standards of Field Work. 17 See GAO Government Audit Standards (December 1, 2011), 1.04.

http://www.epa.gov/oecaerth/resources/policies/incentives/auditing/auditpolicy51100.pdf�

http://www.ferc.gov/legal/staff-reports/11-17-11-enforcement.pdf�

7

dealing with ethics, independence, auditors’ professional competence and judgment, quality control, the performance of field work and reporting.”18

IV. The End State of the Compliance Monitoring and Enforcement Program

A. Transition to Compliance Monitoring Based on Risk

The ERO Enterprise is in the “assurance” business. There are three common risks – inherent risk19, control risk20, and detection risk,21

that must be considered. The FERC approved reliability paradigm already addresses inherent risk to the BES in the functional model, tiers of standards, and degrees of violations. Accordingly, the Regional Entities’ compliance staffs now seek to understand the inherent risk posed by Registered Entities to the BES by considering such factors as their registered functions and applicable standards, as well as their size, geography, technological capability, and past performance.

To move away from the existing compliance monitoring processes and incorporate a risk-based approach, the Regions will also need to understand the control risk posed by the Registered Entities, an effort that would require examining the procedures and controls22 those entities have in place to reduce risk and comply with the standards. An agreed-upon method or set of criteria used by the ERO Enterprise that adequately addresses control risk will be developed through the course of the pilot project.23

18 Id. at 1.05.

While the assessment methodology will be based on consistent foundational audit principles, the consideration of risk and actual design of controls will vary, as no two entities are exactly alike in system design, configuration, programs, plans, and business plans or functions performed. This approach therefore takes into account the differences in Registered Entities and the risks posed to the BES. It also reflects the well-established assurance work practice to document an understanding of controls during the conduct of work as opposed to using a generic one size fits all approach that ignores or does

19 Inherent risk is the risk posed by the Registered Entity because of intrinsic factors such as its registered functions. For example, all other factors being equal a TOP (Transmission Operator) poses more inherent risk to BES reliability than a PSE (Purchasing-Selling Entity). 20 Control Risk refers to the risk that a violation or risk to BES reliability could occur but may not be detected and corrected or prevented by the Registered Entity's compliance program and internal control mechanism. 21 Detection risk is the risk that the ERO Enterprise will not identify a serious or higher risk to BES reliability. Detection risk increases when inherent risk or control risk increases. Therefore, when control risk and/or inherent risk is high, audit scope and procedures must increase. 22 See GAO Government Audit Standards (December 1, 2011), 6.16-6.22, 5.44(b.), citing Institute of Internal Auditors (IIA) International Standards for the Professional Practice of Internal Auditing. 23 Criteria such as the five principles of “highly reliable organizations” may be used in the beginning and refined over time – those five principles being: preoccupation with failure, reluctance to simplify, sensitivity to operations, commitment to resilience, and deference to expertise. See generally Kathleen Sutcliffe and Karl Weick, Managing the Unexpected, Resilient Performance in an Age of Uncertainty, John Wiley & Sons (2d ed. 2007).

8

not take into account the company’s internal controls or the risk posed by the Registered Entity. Once the ERO Enterprise establishes the method for understanding Registered Entities’ risk and controls, the Regional Entities would refer to these characteristics to assess, evaluate and document the strength of those controls as part of their audits and to plan other compliance work. During the course of the pilot project the ERO will develop the practices, procedures and training to ensure consistency across the eight Regional Entities. During full deployment the ERO will continue to provide oversight and work with the eight Regional Entities to develop best practices and ensure consistency (and where applicable uniformity). Understanding both the risk and the environment within which the risk is occurring as well the Registered Entities’ internal controls, the Regional Entities would take existing controls into account to develop the scope, method, and frequency of their compliance work.24

The Regional Entities would also recognize that Registered Entities may exhibit varying levels of maturity vis-à-vis other members of the industry and/or in regard to their own distribution of resources.

These changes can be implemented by using the existing compliance monitoring tools including audits, spot checks, self-certifications, and data submittals. These tools can also be tailored both in terms of scope, conduct, and frequency based on risk and the Registered Entities’ internal controls. Registered Entities that demonstrate an acceptable level of controls would be benefited by more focused testing because the risk controls could be documented and generally relied upon by the compliance staff in the conduct of the work. The long-reaching benefits to reliability and to the industry members will be significant. Registered Entities will be encouraged to self-assess their actual controls on an ongoing basis and self-report any instances of non-compliance. These self-reports, absent significant risk to the BES, will be recorded by the Regional Entity in a segregated database without additional regulatory filings or approvals. The Regional Entity’s determinations documented by work papers will be final. The Regional Entity will be accountable for and subject to oversight and audit by NERC and by FERC for the conduct of its work. The work of the Regional Entities’ compliance personnel and the efforts by Registered Entities to demonstrate compliance will have a more focused scope. Thus, as a result of Registered Entities’ implementing acceptable risk controls and self-reporting any instances of non-compliance, the cost of compliance will be aligned with the management of reliability risks and ultimately the cost of compliance will be 24 Evaluating risk controls along these lines is not novel, and has been used in other industries, for example with respect to Audit Standard-5 (AS-5). Approved by the Securities Exchange Commission, AS-5 allows auditors to scale the scope of an audit based on the strength of controls developed by the company being audited. See PCAOB Release No. 2007-005A (June 12, 2007). This method is also consistent with the GAO standards relating to internal controls. See GAO Government Audit Standards (December 1, 2011), paragraphs 6.16 - 6.22.

9

lower. The investments in strong procedures around reliability and security will have a far greater payoff in terms of the reliability and resiliency of the BES. Robust compliance monitoring will not only improve BES reliability but will also provide value for both the ERO Enterprise and Registered Entities.25

B. Transition to Prioritizing and Treating Violations in Accordance with their Risk

With an understanding of a Registered Entity’s inherent and control risk, the Regional Entities’ staff would then be able to consider whether and to what extent that entity’s compliance with the standards poses a risk to BES reliability. The ERO Enterprise’s26

If a Regional Entity declined to pursue a matter, it would be recorded in a database

compliance monitoring and enforcement discretion will be guided by an understanding of the risk; the environment within which the risk is occurring; the Registered Entities’ internal controls; any patterns of non-compliance; and the significance of the potential violation to BES reliability given the complexity, location, nature and size of the Registered Entity. Errors or potential violations that are detected through internal controls, corrected through a strong compliance culture, and self-reported generally should not be punished with administrative process, enforcement proceedings, or penalties absent a material risk to the BES.

27

that NERC and FERC could audit. This will enable the ERO Enterprise and the Registered Entities to expend their resources more efficiently and effectively, and shift focus beyond compliance risk to include meaningful self-assessments and an evaluation of risk to the BES, thereby improving the standards development process. Traditional enforcement will be reserved for matters that pose a serious or higher risk to the BES and penalties will be assessed to send clear signals to the industry about the most significant risks in order to create change.

This approach will introduce greater flexibility into the ERO Enterprise practices, which will allow it to focus on the higher risks to reliability while simultaneously providing clear signals to the Registered Entities about the ERO Enterprise’s identified areas of concern and its risk prioritization. Moreover, this risk-based regulatory strategy will encourage strong internal controls and self-reporting such that self-reporting will be an objective measure of its success.

25 See Ernst & Young, Leveraging Value from Internal Controls, 5 ( 2006)(“By not aligning risk management and internal controls investments with strategic initiatives, companies are jeopardizing operational and financial performance and, over the long run, will not optimize return to shareholders.”). http://www.section404.org/UserFiles/File/research/Ernst/44_ernst_young_leveraging_value_from_internal_controls.pdf 26 The ERO Enterprise refers to NERC and the eight Regional Entities. 27 The database must be uniform across the eight Regional Entities and must be administratively easy for both Regional Entities and Registered Entities to use.

http://www.section404.org/UserFiles/File/research/Ernst/44_ernst_young_leveraging_value_from_internal_controls.pdf�

http://www.section404.org/UserFiles/File/research/Ernst/44_ernst_young_leveraging_value_from_internal_controls.pdf�

10

As the Commission has stated, “[a]chieving compliance, not assessing penalties is the central goal of our enforcement efforts.”28

C. Transition to Utilizing Compliance Monitoring and Enforcement to Send Meaningful Signals Based on Risk

The ERO Enterprise will refine its use of the compliance monitoring and enforcement process to ensure that it provides more meaningful signals to the Registered Entities about the ERO Enterprise’s identified areas of concern and its risk prioritization. Going forward, the Regional Entity may decline to pursue possible violations that are promptly identified and reported as the result of an effective internal compliance program or controls before the occurrence of any harm. These matters will be recorded in a data base. The matter is then final as to the Registered Entity; the Regional Entity’s decision and work papers are subject to audit by NERC and by FERC. This is important because it encourages the regulated community to adopt and enhance existing strong, effective controls which includes the correction of errors or instances of non-compliance that are detected. BES reliability depends on robust compliance programs and internal controls. The ERO Enterprise will retain the ability to impose penalties up to the statutory maximum and/or increased monitoring and broader audit scope, for those violations that pose a serious or higher risk and/or represent the failure to implement adequate controls. Making a clear distinction between the ERO’s response to violations that are detected, assessed and mitigated pursuant to robust internal controls and compliance programs and those matters that are discovered by the ERO or pose a serious risk to the BES will provide unambiguous signals about the ERO Enterprise’s identified areas of concern and risk prioritization. More importantly, Registered Entities will strengthen their existing internal controls and compliance programs that promptly detect, assess, correct and self-report possible issues of noncompliance to the ERO Enterprise.

D. Transition to Reliability Standards Based on Risk

The ERO Enterprise will develop a feedback loop from compliance monitoring and enforcement to the standards development process that will assist in the identification and development of Reliability Standards that are intended to address the most significant risks to BES reliability. The ERO Enterprise will continue to leverage industry and ERO Enterprise subject matter experts in the standards development process and support those subject matter expert teams

28 See Policy Statement on Compliance, 125 FERC ¶ 61,058 (2008) at P.1.

11

with legal and compliance staff expertise to help ensure that upon implementation the Reliability Standards address the intended risk to reliability and are clear, concise and narrowly drawn to avoid unintended consequences.

When a given Reliability Standard is found to be ineffective because it has only a minimal impact on reducing risk (or in fact increases risk), the ERO Enterprise will work to revise, replace or eliminate the Reliability Standard.

V. Next Steps: Implementing Risk-Based Concepts NERC will address the key components of these changes in an informational filing made March 2013 to FERC. The key components include: (1) restyling the ERO’s overall compliance approach to conform to well-established audit principles as described herein including the right to decline to pursue violations across the ERO Enterprise; (2) establishing the requirements for Regional Entity’s records to facilitate NERC and FERC oversight; (3) establishing processes for information flow between compliance functions and enforcement functions as well as an open, transparent and clear approach as to which matters will be subject to enforcement procedures; and (4) redesigning the enforcement strategy to focus on serious or higher risks to the BES. Presentations regarding these concepts and next steps will be made at the November NERC BOTCC, MRC and BOT meetings. In addition, there will be subsequent presentations at regularly scheduled meetings and supplemental webinars as needed to introduce and discuss the key change state elements and related activities. The ERO Enterprise anticipates that this model will mature and be fully deployed over the next three to five years. The ERO Enterprise will also introduce these approaches through a pilot project29

29The pilot project will performed across and among the regions with ERO oversight in conjunction with selected registered entities, the results of which will be communicated as lessons learned in the overall development of the Compliance Enforcement Initiative.

as the initial steps towards full implementation. FERC has previously recognized the value of pilot projects, pointing out that “[n]o matter how good the data suggesting that a regulatory change should be made, there is no substitute for reviewing the actual results of a regulatory action." Order No. 637, FERC Stats. & Regs. ¶ 31,091 (2000) at 31,279. The U.S. Court of Appeals for the D.C. Circuit agrees: “For at least 30 years this court has given special deference to agency development of such experiments, precisely because of the advantages of data developed in

12

the real world.”30

The goal of each pilot project will be to further define the risk-based approach and develop effective tools, training, procedures, and policies to allow the ERO Enterprise to deploy these concepts in a consistent manner across all Regional Entities. The ERO Enterprise will keep FERC apprised of the progress of the pilot projects, and at the conclusion of each pilot project, the ERO Enterprise will make appropriate revisions to the pilot projects and any necessary filings to deploy the pilot projects throughout the ERO Enterprise.

Beginning in November 2012 through early February 2013, NERC will be issuing a series of concept papers addressing the four key components described, the pilot project and a draft filing.

VI. Conclusion The ERO Enterprise believes that the following benefits will result from employing risk-based methods:

• Improved Bulk Electric System reliability due to Registered Entities’ enhancing their existing policies, processes and procedures; internal controls; and cultures of compliance that self-assess risk and compliance and promptly correct matters before they have a material impact on reliability.

• Improved standards development and retirement process because there is a compliance monitoring and enforcement feedback loop.

• Improved utilization of all participants’ resources due to focus on higher risks. • Increased efficiency for the ERO Enterprise and Registered Entities resulting in lower

administrative costs because not all potential violations are processed.

• Drive consistency with the eight Regional Entities in compliance and enforcement. • Improved Bulk Electric System reliability due to the use of the compliance monitoring

and enforcement process to provide more meaningful signals about the ERO Enterprise’s identified areas of concern and risk prioritization.

30 See, Interstate Natural Gas Association of America v. Federal Energy Regulatory Commission, 285 F.3d 18, 24 (D.C. Cir. 2001)(http://ftp.resource.org/courts.gov/c/F3/285/285.F3d.18.00-1395.00-1380.00-1367.00-1360.00-1410.html)

http://ftp.resource.org/courts.gov/c/F3/285/285.F3d.18.00-1395.00-1380.00-1367.00-1360.00-1410.html�

http://ftp.resource.org/courts.gov/c/F3/285/285.F3d.18.00-1395.00-1380.00-1367.00-1360.00-1410.html�


ERO Scope of Activities Input Group

Action Information Background During its August 15, 2012 meeting, the Member Representatives Committee (MRC) proposed to assist NERC and the Regional Entities in defining the scope of the ERO and recommend structured process to enable MRC member and stakeholder advice and guidance as part of the annual business planning and budget process. The ERO Scope of Activities Input Group was formed to work closely with NERC and the Regional Entities. The input group is chaired by Vice Chair Carol Chinn and member representive Bill Gallagher. Other member representatives and participants include: John Anderson, Tom Burgess, Mike Penstone and Ed Schwerdt, Northeast Power Coordinating Council. NERC participants include Mike Walker, David Cook, Charlie Berardesco and Holly Mann. Status The input group routinely met throughout September and October by conference call. The discussions focused on:

• The schedule and structure of the annual business plan and budget process.

• The goals, objectives, and process for providing MRC and stakeholder input into the development of the ERO’s goals, objectives and priorities through the business plan and budget process.

• The provisions of NERC’s bylaws regarding the MRC’s role in providing advice and recommendations to the Board with respect to the development of annual budgets, business plans and funding mechanisms, and other matters.

• The preliminary work by NERC and the Regional Entities regarding the development of ERO Strategic Plan goals, objectives and priorities for the 2014-2016 planning period.

• The structure and scope of section 215 guidelines which NERC has proposed to develop in accordance with the FERC audit recommendations.

• The preliminary development of a process and structure for ongoing input by the MRC and stakeholders in the development of ERO priorities and associated goals, objectives, business plans and budgets.

The group intends to continue its routine meetings to address each of these focus areas, at least until a point in time where a more formal input process is implemented by the MRC. At the November 6, 2012 meeting, Mike Walker will provide the Committee with an overview of the draft 2014 Businees Plan and Budget schedule and the key timeframes for input by the MRC and other stakeholders. Mike Walker will also describe the plan for obtaining stakeholder input on the guidelines being developed for determing the proper scope of activities under section 215.

The working group members will also discuss and seek the MRC’s input regarding the benefits of forming, as well as the structure and governance of, a process and mechanism for ongoing input by the MRC in the ERO’s formulation of its long-term and annual priorities, goals, objectives, business plans and budgets. Enclosed Attachments

1. Draft of 2014 Business Plan and Budget Schedule

2. NERC Bylaws Article VIII, Section 1 - Excerpt Regarding MRC Advice and Recommendations to NERC

Draft – October 2012

2014-2016 Business Planning Schedule (Working Draft)

Highlights

• Includes the 2012 schedule for the 2013 business planning and budgeting process, as well as a draft schedule for the 2014 business planning and budgeting process.

• Next three-year business planning cycle contemplates the development of goals and objectives for the 2014-2016 time period (“Valued Outcomes” document will be used to guide goals and objectives discussions).

• Schedule anticipates early start to the process (Q4 2012), with the objective of having final draft three-year goals and objectives in place by February 2013 for inclusion in the first draft of NERC and Regional Entity business plans and budgets to be posted in early May 2013.

• Process expected to facilitate earlier input to Regional Entity business planning and budgeting, as well as demonstrate ongoing and increased coordination regarding long-term planning efforts.

• A column on the far right entitled “Related Stakeholder and Committee Initiatives” is to identify and coordinate with key committees and/or and stakeholders which affect the business planning and budgeting process. For example, there are a number of key working groups and committees that engage in planning and decision making that directly impact ERO budgets or initiatives. This schedule will also need to incorporate any parallel processes related to the NERC and Regional Entity Business Plans and Budgets which result from the implementation of the final recommendations and requirements contained in the FERC 2013 business plan and budget and/or audit orders applicable to NERC and the Regional Entities.

Draft – October 2012 2

DATES

2013 BP&B 2014-16 BP&B Related Stakeholder-NERC Committee

Initiatives NERC Regional Entity NERC Regional Entity February 3, 2012 -11:00

a.m. ET

FAC Conference Call to discuss quarterly business; includes update on 2013 BP&B process and schedule which is posted as part of agenda materials.

February 17, 2012

Common 2013 BP&B Assumptions posted for comment.

March 9, 2012 Comments due on Common 2013 BP&B Assumptions.

April 4, 2012 Meeting with trades to discuss 2013 BP&B (NERC DC office).

April 16, 2012 Submittal to Regional Entities of Preliminary Internal Draft of NERC 2013 business plan and budget.

Submittal to NERC of Preliminary Internal Draft of Regional Entity business plan and budgets for circulation among NERC program


DATES


Initiatives NERC Regional Entity NERC Regional Entity managers for review and feedback.

May 2, 2012 Draft #1 of 2013 NERC Business Plan and Budget posted and sent to FAC.

May 3, 2012 – 10:00am ET

FAC conference call and webinar to discuss Draft #1 of NERC 2013 business plan and budget.

May 4, 2012

Draft #1 of 2013 RE Business Plans and Budgets posted on NERC website.

May 8, 2012 FAC Meeting MRC Meeting-Presentation of Draft 2013 Business Plan and Budget.

May 18, 2012 FAC conference webinar to review Regional Entities’ 2013 Business Plans and Budgets. Regional Entities present draft business plans and budgets to NERC FAC.

May 25, 2012 Comments due on Draft #1 of NERC 2013 Business Plan and Budget.


DATES


Initiatives NERC Regional Entity NERC Regional Entity May 31, 2012 NERC files 2011

NERC and Regional Entity budget to actual true up with FERC.

June 1, 2012 Draft #2 of 2013 NERC Business Plan and Budget posted.

Board Meeting Dates for Review and Approval of Regional Entity 2013 Business Plans and Budgets: SPP – June 19 RFC – June 22 NPCC – June 26 TRE – June 26 WECC – June 26 FRCC – June 28 MRO – June 28 SERC – July 11

July 6, 2012 Stakeholder Comments due on NERC Draft #2 2013 Business Plan and Budget.

July 9, 2012 Final Regional Entity budget


DATES


Initiatives NERC Regional Entity NERC Regional Entity submittal due – approved by Regional Entity boards and final list of LSEs and NEL data.

July 19, 2012 – 10:30 a.m.

ET

FAC webinar to review Draft #2 of 2013 NERC Business Plan and Budget and final Regional Entity budget submittals.

Regional Entities present final business plans and budgets to NERC FAC.

August 7, 2012

Final NERC and Regional Entity 2013 business plans, budgets and assessments posted and mailed to FAC, Board of Trustees and Member Representatives Committee.

August 15, 2012

Recap of 2013 BP&B process with MRC, general overview of 2014 BP&B planning process. FAC Meeting to (1) review and recommend approval of NERC and Regional Entity final 2013 business plans,


DATES


Initiatives NERC Regional Entity NERC Regional Entity budgets and assessments (2) review NERC and RE Q2 2012 budget variance reports and year end projections.

August 16, 2012

NERC and RE 2013 business plans, budgets and assessments presented to Board of Trustees for approval.

August 16, 2012

Preliminary kick-off, Closed EMG meeting with NERC CEO, Regional Managers and Mike Walker: • Discuss process and timeline for developing 3 year

(2014- 2016) planning, goals, objectives, measures, and assumptions (Process and schedule only)

August 24, 2012

Submit 2013 BP&B package to FERC and Canadian provincial authorities for approval. Package to include: (1) the NERC and RE business plans and budgets approved by the Board of Trustees, (2) NERC’s annual funding requirement (including regional entity costs for delegated functions) and (3) the mechanism for assessing charges to recover that annual funding requirement.

Friday, September

21, 2012

Closed Regional Entity Executive and NERC CEO strategic planning session.


DATES


Initiatives NERC Regional Entity NERC Regional Entity Monday, Sept

24 MRC ERO Scope Input

Group and CEI End-State Input Group conference calls

Mon, Oct 1, 2012

NERC staff provides materials with the MRC ERO BP&B Scope Input Group for further review/discussion

MRC CEI End-State Input Group meets in Washington DC with Regional staff involved in whitepaper development.

Tues, Oct 2, 2012

Share preliminary BP&B schedule with Trades.

Wed, Oct 10, 2012

MRC ERO Scope Input Group conference call

October 15, 2012

Regions will submit comments on the draft ERO-wide goals for 2014-16 and the measures for 2013. Each goal and measure should help to achieve the valued outcomes in each of the strategic focus areas.

MRC CEI End-State Input Group conference call

Tues, Oct 16, 2012

NERC staff provides materials with the MRC ERO Scope Input Group for review/discussion


DATES


Initiatives NERC Regional Entity NERC Regional Entity October 18

2012 Webinar

Webinar meeting of NERC and Regional Entity senior staff to review and respond to drafts of 2014-16 goals and 2013 measures.

Fri, Oct 19, 2012

MRC ERO Scope Input Group conference call

October 22, 2012

Reliability Issues Steering Committee (RISC) Open meeting - Atlanta

October 26, 2012

ERO EMG monthly conference call

October 31, 2012 11:00

am ET

NERC FAC 4th Quarter Conference Call- update on BP&B process and schedule as part of agenda

November 1, 2012

BOT request for policy input due to NERC.

November 5, 2012

ERO EMG meeting in New Orleans to refine 2014-16 goals and 2013 measures.

November 6, 2012

Brief MRC on status of BP&B process and discussions with MRC input group on scope of NERC Activities

November 7, 2012

BOT review and discussion of November 6, 2012 MRC briefing. Reliability Issues Steering Committee (RISC) Open meeting.


DATES


Initiatives NERC Regional Entity NERC Regional Entity Wednesday, November 7,

2012

Closed ERO EMG meeting with NERC CEO, RMs in New Orleans. Further discuss 2014-16 goals and objectives. Consider feedback from regional and NERC staffs, as well as MRC input group.

November ? Assuming FERC Audit Order issued and subject to the findings in that order – Post draft Section 215 written criteria for comment

December 2012

Finalize draft 2014-2016 goals and objectives

December 5-6, 2012

CCC meeting

December 11-13, 2012

OC/PC/CIPC meetings

December 14, 2012


December 17, 2012

Reliability Issues Steering Committee (RISC) Open meeting

December 18, 2012

Closed ERO EMG meeting with NERC CEO, RMs at SERC.

January, 2013

Convene forums to review draft Section 215 written criteria which were posted for comment. Obtain input from Trades.


DATES


Initiatives NERC Regional Entity NERC Regional Entity January , 2013 Post draft 2014-2016

goals, objectives for comment.

Kicks off formal process for broad stakeholder input on ERO 2014-2016 goals and objectives; 2014 BP&B priorities

January 24, 2013


January 25, 2013


February 2013 Convene forums for input on goals, objectives and priorities.

February 5, 2013

ERO EMG meeting in San Diego

February 6-7, 2013

MRC and BOT meetings (San Diego)

February 7, 2013

Closed ERO EMG meeting with NERC CEO, RMs in San Diego

February 2013

Finalize goals, objectives and common assumptions for inclusion in draft 1 of NERC 2014 BP&B to be posted in early May, 2013

February 12, 2013


February 18, 2013

(target date only)

Draft CEI filing release by NERC


DATES


Initiatives NERC Regional Entity NERC Regional Entity March, 2013 (target date

only)

Subject to audit order, make compliance filing of Section 215 written criteria with FERC

March 5-6, 2013

OC/PC/CIPC meetings

March 12, 2013


March 13-14, 2013

CCC meeting

March 15, 2013

CEI filing at FERC

March- April

2013

Work on Draft 1 of 2014 BP&B Continue to work with MRC Task Force; obtain input from Trades

April , 2013 Closed FAC Meeting – Review of personnel, contracts and other assumptions for 2013 BP&B

April 16, 2012 Reliability Issues Steering Committee (RISC) Open meeting

Tuesday, April 30, 2013

Target date for Draft #1 of 2014 NERC

2012 Regional Entity True-Up files due to NERC


DATES


Initiatives NERC Regional Entity NERC Regional Entity Business Plan and Budget posted and sent to FAC.

Friday, May 3, 2013-

10:00am ET

FAC conference call and webinar to discuss Draft #1 of 2014 NERC business plan and budget

Monday, May 6, 2013

Draft 1 of RE 2014 Business Plans and Budgets posted on NERC website

Wednesday, May 8, 2013

FAC Meeting- update on 2014 BP&B as part of agenda; quarterly business includes (1) review of year end audited financial statements for NERC and Regions (2) update on 2014 BP&B.


MRC Meeting-Presentation of Draft 2014 BP&B

May [date TBD], 2013

Meeting to provide FERC budget staff with overview of 2014 NERC and Regional Entity Business Plans and Budgets

Convene meeting with trades to review and obtain input on 2014 NERC and Regional Entity Business Plans and Budgets


FAC conference webinar to review RE 2014 BP&Bs* * (All BOT members invited)

Regional Entities present draft 2014 BP&Bs to NERC FAC


DATES


Initiatives NERC Regional Entity NERC Regional Entity May 22, 2013 Reliability Issues Steering Committee (RISC) Open meeting

Thursday, May 30, 2013

Comments due on 1st Draft of NERC BP&B. NERC and Regional Entity 2012 budget to actual true up filing due at FERC

June 2013 Regional Entity board meeting dates for review and approval of Regional Entity 2014 Business Plans and Budgets FRCC – June MRO – June NPCC – June RFC – June 21 SERC – July 10 SPP – June 18 TRE – June WECC – June 26

Monday, June 10, 2013

Post Draft #2 of 2014 NERC Business Plan and Budget

June 18, 2013 Reliability Issues Steering Committee (RISC) Open meeting

Tuesday, July 9, 2013

Final RE 2014 budget submittal due – approved by RE board and final list of LSEs and NEL data

Wednesday, July 10, 2013

Stakeholder Comments due on 2014 NERC Draft #2


DATES


Initiatives NERC Regional Entity NERC Regional Entity July 11, 2013 Reliability Issues Steering Committee (RISC) Open meeting

Friday, July 19, 2013

FAC webinar to review Draft #2 of 2014 NERC BP&B and final RE budget submittals

REs present final 2014 BP&Bs to NERC FAC

Monday, July 29, 2013

Final 2014 NERC and RE business plans, budgets and assessments posted and mailed to FAC, Board of Trustees and Member Representatives Committee.

August 8, 2013


Monday, August 12,

2013

FAC Meeting to review and recommend approval of NERC and RE final 2014 business plans, budgets and assessments

Wednesday, August 14,

2013 (Montreal)

Recap of 2014 BP&B process and discussion of 2015 BP&B Process at MRC meeting

Thursday, August 15,

2013 (Montreal)

NERC and RE 2014 business plans, budgets and assessments


DATES


Initiatives NERC Regional Entity NERC Regional Entity presented to Board of Trustees for approval.

Friday, August 23, 2013

Submit package to FERC and Canadian provincial authorities for approval. Package to include: (1) the 2014 NERC and RE business plans and budgets approved by the Board of Trustees, (2) NERC’s annual funding requirement (including regional entity costs for delegated functions) and (3) the mechanism for assessing charges to recover that annual funding requirement.

September 19, 2013


f. The assistant secretary-treasurer shall have such duties and possess such other powers as may be delegated to him or her by the president.

ARTICLE VII Committees of the Corporation

Section 1 � Committees of the Corporation� In addition to those committees specified by these Bylaws, to which the board shall appoint members in accordance with the requirements of these Bylaws, the board may by resolution create standing committees of the Corporation; and may in addition by resolution appoint such other committees as the board deems necessary to carry out the purposes of the Corporation. The board shall appoint standing committees and other committees of the Corporation that are representative of members, other interested parties and the public, that provide for balanced decision making, and that include persons with outstanding technical knowledge and experience. All appointments of committees of the Corporation shall provide the opportunity for an equitable number of members from the United States and Canada (and from Mexico after the Corporation receives recognition by appropriate governmental authorities in Mexico as its electric reliability organization) to be appointed to each committee in approximate proportion to each country’s percentage of the total NEL. All committees shall have such scope and duties, not inconsistent with law, as are specified in these Bylaws and the Rules of Procedure of the Corporation or otherwise determined by the board.

ARTICLE VIII Member Representatives Committee

Section 1 � Member Representatives Committee� The Corporation shall have a Member Representatives Committee that shall have the following rights and obligations:

a. to elect the independent trustees, in accordance with Article III, Section 6;

b. to vote on amendments to the Bylaws, in accordance with Article XVI; and

c. to provide advice and recommendations to the board with respect to the development of annual budgets, business plans and funding mechanisms, and other matters pertinent to the purpose and operations of the Corporation.

Because it is elected by the members of the Corporation and not appointed by the board, the Member Representatives Committee shall not be a standing committee of the Corporation, but is authorized to provide its advice and recommendations directly to the board.

Section 2 � Composition of the Member Representatives Committee� The Member Representatives Committee shall consist of (i) two representatives from each sector except the government representative sector and the regional entity sector, (ii) two voting representatives from the regional entity sector, with the remaining members of that sector being non-voting members of the Member Representatives Committee, (iii) the chairman and vice chairman of the Member Representatives Committee, (iv) any additional Canadian representatives as are

Bylaws of the North American Electric Reliability Corporation 14 Effective October 14, 2009

selected pursuant to Section 4 of this Article VIII, and (v) the following representatives of the government representatives sector: two representatives of the United States federal government, one representative of the Canadian federal government, two representatives of state governments, and one representative of a provincial government, all of whom shall be nonvoting members of the Member Representatives Committee except the two representatives of state governments. The representatives of each sector shall be members of the Corporation, or officers or executive-level employees, agents or representatives of members of the Corporation, in that sector; provided, that at any time only one officer, employee, agent, or representative of a member in a sector may be a representative from that sector. No member of the board shall be a member of the Member Representatives Committee. The board may by resolution create additional nonvoting positions on the Member Representatives Committee at the written request of any group of members of the Corporation that believes its interests are not adequately represented on the Member Representatives Committee.

In order to provide that the terms of approximately one-half of the members of the Member Representatives Committee expire each year, on the initial Member Representatives Committee one-half of the representatives from each sector shall serve a term expiring at the next annual meeting, and one-half of the representatives from each sector shall serve a term expiring at the second succeeding annual meeting, in each case held pursuant to Section 7 of this Article VIII.

Following the expiration of the terms of the members of the initial Member Representatives Committee as provided above, each member of the Member Representatives Committee shall thereafter serve a term of two years commencing at an annual meeting held pursuant to Section 7 of this Article VIII and ending at the second succeeding annual meeting. There shall be no limit on the number of terms that a member of the Corporation, or an employee, agent, or representative of a member of the Corporation, may serve on the Member Representatives Committee.

Section 3 — Election of Members of the Member Representatives Committee

a. Unless a sector adopts an alternative election procedure, the annual election of representatives from each sector to the Member Representatives Committee, and any election to fill a vacancy, shall be conducted in accordance with the following process, which shall be administered by the officers of the Corporation. During the period beginning approximately ninety (90) days and ending approximately thirty (30) days prior to an annual election, or beginning approximately forty-five (45) days and ending approximately fifteen (15) days prior to an election to fill a vacancy, nominations may be submitted for candidates for election to the Member Representatives Committee, provided that for the initial election the period may begin as soon as these bylaws are made effective and may end approximately fifteen (15) days prior to the election. A nominee for election as a sector representative must be a member, or an officer, executive-level employee or agent of a member, in that sector. No more than one nominee who is an officer, executive-level employee or agent of a member or its affiliates may stand for election in any single sector; if more than one officer, employee or agent of a member or its affiliates is nominated


for election from a sector, the member shall designate which such nominee shall stand for election. The election of representatives shall be conducted over a period of ten (10) days using an electronic process. Each member in a sector shall have one vote for each representative to be elected from the sector in that election, and may cast no more than one vote for any nominee. The nominee receiving the highest number of votes in each sector shall be elected to the representative position to be filled from that sector; if there is more than one representative position to be filled from a sector, the nominee receiving the second highest number of votes shall also be elected, and so forth. Provided, that to be elected a nominee must receive a number of votes equal to a simple majority of the members in the sector casting votes in the election. If no nominee in a sector receives a simple majority of votes cast in the first ballot, a second ballot shall be conducted which shall be limited to the number of candidates receiving the two (2) highest vote totals on the first ballot (or to the number of candidates receiving the four (4) highest vote totals on the first ballot if two representative positions remain to be filled, and so forth). The nominee or nominees receiving the highest total or totals of votes on the second ballot shall be elected to the representative position or positions remaining to be filled for the sector.

A sector may adopt an alternative procedure to the foregoing to nominate and elect its representatives to the Member Representatives Committee if (i) the alternative procedure is consistent in principle with the procedures specified in the preceding paragraph of this Section 3a, and (ii) the alternative procedure is approved by vote of at least two-thirds of the members in the sector. Any alternative procedure is subject to review and disapproval by the board.

Section 4 � Adequate Representation of Canadian Interests on the Member Representatives Committee � In addition to the requirements for composition of the Member Representatives Committee specified in Section 1 of this Article VIII, the Member Representatives Committee shall contain a number of Canadian voting representatives equal to the percentage of the NEL of Canada to the total NEL of the United States and Canada, times the total number of voting members on the Member Representatives Committee, rounded up to the next whole number. If the annual selection of members of the Member Representatives Committee pursuant to Section 3 of this Article VIII does not result in the number of Canadian voting representatives provided for herein on the Member Representatives Committee, then the candidate who received the highest fraction of the sector vote among those candidates who would have qualified as Canadian voting representatives but were not elected to the Member Representatives Committee shall be added to the Member Representatives Committee. Additional Canadian voting representatives shall be added to the Member Representatives Committee through this selection process until the Member Representatives Committee includes a number of Canadian voting representatives equal to the percentage of the NEL of Canada to the total NEL of the United States and Canada, times the total number of voting members on the Member Representatives Committee, rounded up to the next whole number. Provided, that no more than one such additional Canadian voting representative shall be selected from a sector, except that if this limitation precludes the addition of the number of additional Canadian voting representatives required by the previous


sentence, then no more than two Canadian voting representatives may be selected from the same sector. Such additional Canadian voting representatives shall be representatives of the sectors in which they stood for election, and shall serve terms expiring at the next annual meeting of the Member Representatives Committee pursuant to Section 7 of this Article VIII. For purposes of this Section 4, “Canadian” means one of the following: (a) a company or association incorporated or organized under the laws of Canada or of a province of Canada that is a member of the Corporation, or its designated representative irrespective of nationality; (b) an agency of a federal, provincial, or local government in Canada that is a member of the Corporation, or its designated representative irrespective of nationality; or (c) a person who is a Canadian citizen residing in Canada and is a member of the Corporation.

When the Corporation receives recognition from appropriate governmental authorities in Mexico as the electric reliability organization, this provision will be expanded to provide for adequate representation of Mexican interests on the Member Representatives Committee.

Section 5 � Officers of the Member Representatives Committee � At the initial meeting of the Member Representatives Committee, and annually thereafter prior to the annual election of representatives to the Member Representatives Committee, the Member Representatives Committee shall select a chairman and vice chairman from among its voting members by majority vote of the members of the Member Representatives Committee to serve as chairman and vice chairman of the Member Representatives Committee during the upcoming year; provided, that the incumbent chairman and vice chairman shall not vote or otherwise participate in the selection of the incoming chairman and vice-chairman. The newly selected chairman and vice chairman shall not have been representatives of the same sector. Selection of the chairman and vice chairman shall not be subject to approval of the board. The chairman and vice chairman, upon assuming such positions, shall cease to act as representatives of the sectors that elected them as representatives to the Member Representatives Committee and shall thereafter be responsible for acting in the best interests of the members as a whole.

Section 6 � Vacancies on the Member Representatives Committee � In the event that any member of the Member Representatives Committee ceases to serve as a member of the Member Representatives Committee as a result of his or her death, resignation, retirement, disqualification, or removal or other cause, the members in the sector of which such member was a representative shall elect, as soon thereafter as reasonably possible, and in accordance with the procedures in Sections 3 and 4 of this Article VIII, a new member to replace the member of the Member Representatives Committee who ceases to serve. Except with regard to the selection of the chairman and vice chairman at the initial meeting of the Member Representatives Committee, the vacancies in the sector representatives created by the selection of the chair and vice chair pursuant to Section 5 of this Article VIII shall be filled at the annual election of representatives to the Member Representatives Committee that is next held following the election of the chairman and vice chairman. In the case of the selection of the chairman and vice chairman at the initial meeting of the Member Representatives Committee, the sector representative vacancies created thereby shall be filled as soon thereafter as reasonably possible in accordance with the procedures in Section 3 of this Article VIII for sector representative vacancies.


Section 7 � Annual Meeting of the Member Representatives Committee � An annual meeting of the Member Representatives Committee for the election of independent trustees and to conduct such other business as may come before the meeting shall be held on or about February 1 of each year or as soon thereafter as is reasonably possible. By resolution adopted at any meeting of the Member Representatives Committee, the Member Representatives Committee may provide for additional regular meetings that may be held without further notice to the members of the Member Representatives Committee.

Section 8 � Special Meetings of the Member Representatives Committee� Special meetings of the Member Representatives Committee for any purpose or purposes may be called by the chair of the Member Representatives Committee or by any five (5) members of the Member Representatives Committee, which number shall include representatives from at least three sectors, and require notice given to all members of the Member Representatives Committee not less than seven (7) days prior to the date of the meeting. Such notice shall specify the time, date, place, and purpose or purposes of the meeting and may be given by telephone, telegraph, or other electronic media, or by express delivery.

Section 9 � Quorums and Voting for Meetings of the Member Representatives Committee� The quorum necessary for the transaction of business at meetings of the Member Representatives Committee shall be two-thirds of the voting members of the Member Representatives Committee attending the meeting in person or by proxy. A member of the Member Representatives Committee may give a proxy only to a person who is a member, or an officer, executive-level employee, agent or representative of a member, registered in the same sector. Each voting member of the Member Representatives Committee shall have one (1) vote on any matter coming before the Member Representatives Committee that requires a vote. Except as otherwise expressly provided in the Corporation’s Certificate of Incorporation, these Bylaws or applicable law, actions by members of the Member Representatives Committee shall be approved upon receipt of the affirmative vote of a majority of the voting members of the Member Representatives Committee present and voting, in person or by proxy, at any meeting at which a quorum is present.

Section 10 � Meetings of the Member Representatives Committee to be Open� Notice to the public of the dates, places, and times of meetings of the Member Representatives Committee, and all nonconfidential material provided to the Member Representatives Committee, shall be posted on the Corporation’s Web site, and notice of meetings of the Member Representatives Committee shall be sent electronically to all members of the Corporation, within 24 hours of the time that notice or such material is given to the Member Representatives Committee. Meetings of the Member Representatives Committee shall be open to the public, subject to reasonable limitations due to the availability and size of meeting facilities; provided, that the Member Representatives Committee may meet in or adjourn to closed session to discuss matters of a confidential nature, including but not limited to personnel matters, compliance and enforcement matters, litigation, or commercially sensitive or critical infrastructure information of any entity. Any or all members of, and any other participants in, the Member Representatives Committee may participate in a meeting of the Member Representatives Committee by a means of a communications system by which all


persons participating in the meeting are able to hear each other.

Section 11 � Waivers of Notice of Meetings of the Member Representatives Committee; and Meeting Adjournments� Notice of a meeting of the Member Representatives Committee need not be given to any member of the Member Representatives Committee who signs a waiver of notice, in person or by proxy, whether before or after the meeting, or who attends the meeting without protesting, prior to the conclusion of the meeting, the lack of notice of such meeting. Notice of an adjourned meeting of the Member Representatives Committee need not be given if the time and place to which the meeting is adjourned are announced at the meeting at which the adjournment is taken and if the period of adjournment does not exceed ten (10) days.

Section 12 � Action Without a Meeting of the Member Representatives Committee�Any action required or permitted to be taken at a meeting of the Member Representatives Committee may be taken by the Member Representatives Committee without a meeting if the action is consented to in writing by the number of members of the Member Representatives Committee entitled to vote on the action that would be required to approve the action at a meeting of the Member Representatives Committee with all of its members present. The call for action without a meeting of the Member Representatives Committee may be initiated by the Chair of the Member Representatives Committee or by any five (5) members of the Member Representatives Committee, which number shall include representatives from at least three (3) sectors. Notice of the proposed call for action without a meeting, and all nonconfidential material provided to the Member Representatives Committee in connection with the call for action without a meeting, shall be posted on the Corporation’s Web site within 24 hours of the time notice of the call for action without a meeting or such material is provided to the members of the Members Representative Committee. The members of the Member Representatives Committee shall receive written notice of the results, and the results shall be posted on the Corporation’s Web site, within seven (7) days of the action vote, and all written responses of voting members of the Member Representatives Committee shall be filed with the minutes of the Corporation.

Section 13 � Other Procedures of the Member Representatives Committee� The chairman of the board in office on November 1, 2006, shall preside at the initial meeting of the Member Representatives Committee, until a chairman is selected in accordance with Section 5 of this Article VIII. Except as to any matter as to which the procedure to be followed by the Member Representatives Committee is expressly set forth in these Bylaws, the Member Representatives Committee may adopt such additional procedures, not inconsistent with these Bylaws, as it deems appropriate.

ARTICLE IX Reliability Standards

Section 1 � Development of Reliability Standards � The Corporation shall develop, implement and, in all regions in which necessary governmental approvals have been obtained or authority has been provided, enforce, reliability standards that provide for reliable operation of the bulk power systems of North America. All reliability standards shall be


approved by the board. All reliability standards of the Corporation shall be posted on its Web site. Nothing in this Article shall be deemed to invalidate any standard of the Corporation that was in effect on November 1, 2006.

Section 2 � Procedures for Development of Reliability Standards � The Corporation shall develop reliability standards pursuant to procedures and processes that shall be specified in the Rules of Procedure of the Corporation. The Rules of Procedure shall provide for the development of reliability standards through an open, transparent, and public process that provides for reasonable notice and opportunity for public comment, due process, and balancing of interests and is designed to result in reliability standards that are technically sound. Participation in the process for development of reliability standards shall not be limited to members of the Corporation but rather shall be open to all persons and entities with an interest in the reliable operation of the bulk power system.

Section 3 � Procedures for Determinations of Violations of Reliability Standards and Imposition of Sanctions for Violations � In all regions in which regulatory approval has been obtained or governmental authority has been provided, the Corporation shall consider and make determinations that an owner, operator, or user of the bulk power system has violated a reliability standard, and shall impose sanctions for such violations, pursuant to procedures and processes that shall be specified in the Rules of Procedure of the Corporation. Such procedures and processes shall provide for reasonable notice and opportunity for hearing. Any sanction imposed for a violation of a reliability standard shall bear a reasonable relation to the seriousness of the violation and shall take into consideration efforts of the owner, operator, or user of the bulk power system to remedy the violation in a timely manner. Subject to any necessary action by any applicable governmental authorities, no sanction imposed for a violation of a reliability standard shall take effect until the thirty-first (31) day after the Corporation, where authorized by law or agreement, files with the Commission or other applicable governmental authority notice of the sanction and the record of the proceedings in which the violation and sanction were determined, or such other date as ordered by the Commission or other applicable governmental authority or as prescribed by applicable law.

ARTICLE X Agreements with Regional Entities

Section 1 � Delegation Agreements with Regional Entities � The Corporation may, in accordance with appropriate governmental authority, enter into agreements with regional entities pursuant to which a regional entity shall be delegated the authority of the Corporation to enforce reliability standards within a geographic region of North America and may develop and propose reliability standards to be in effect within such region. All delegation agreements with regional entities shall be approved by the board. No delegation agreement with a regional entity shall be effective with respect to a region until the agreement has received any necessary approval from an applicable governmental authority.

Section 2 � Standards for Delegation Agreements � The Corporation shall be permitted to enter into a delegation agreement with a regional entity only if the board determines that (i)



Initial Report on Reliability Issues Steering Committee Activities Priorities

Action None Background At its August 16, 2012 meeting, NERC’s Board of Trustees (Board) approved the formation of the Reliability Issues Steering Committee (RISC), the RISC Charter that had been developed by the Standards Process Input Group (SPIG), as well as the initial membership of the RISC. Status The RISC held its first public meeting on October 22, 2012 in Atlanta, GA and will be holding its second public meeting immediately following the Board meeting on November 7 in New Orleans, LA. The RISC is reviewing 11 strategic areas that have been compiled from various sources. The 11 areas, plus a descriptive example for each, are listed below:

• Protection Systems: An event occurs because a bad event becomes worse due to a protection system failing to operate correctly.

• Critical Infrastructure Protection: An event occurs because of a malicious attack by a hacker or terrorist.

• Workforce Capability and Human Error: An event occurs because someone (e.g., an operator or a field technician) makes a mistake or has an error in judgment.

• Monitoring and Situational Awareness: An event occurs due to someone (e.g., an operator or a field technician) not understanding the state of the system.

• Transmission Right of Way: An event occurs due to a forced outage of part of the transmission system caused by a right-of-way incursion.

• Planning and Modeling: An event occurs because our models and forecasts were inaccurate and did not predict the problem we experienced.

• Changes To and Within the Industry: An event occurs because the world changed (e.g., environmental regulation, PHEVs, wind and solar, changing resource mix, etc.), and we were not prepared

• Voltage and Reactive: An event occurs because we are not able to maintain voltage stability.

• Equipment Maintenance and Management: An event occurs because we are not maintaining our equipment correctly or on schedule and something failed prematurely.

• Generation Supply: An event occurs because generation is inadequate during a frequency disturbance, and Under-frequency Load Shedding activated.

• High-Impact, Low-Probability: There is a long-term bulk electric system outage because a High-Impact, Low-Probability event occurred, and we were not prepared.

The RISC will evaluate this list of strategic areas to make sure it is complete, as well as to make sure there are no items that should be removed. The RISC will also determine the levels of reliability risk these areas represent to the bulk power system, whether they are adequately controlled, and an overall priority for each strategic area. This prioritization will then be used to develop an overall ERO Reliability Strategy for consideration by the Board, against which NERC and its committees can develop their future work plans and resource allocations. If you have any questions or need additional information, please contact the Director of Reliability Risk Analysis and Control Andy Rodriquez at [email protected].


Agenda Item 7a, b MRC Meeting November 6, 2012

Review of Select Reliability Standards Projects

Reliability Standards Status Report

Action Information Background Review of Select Reliability Standards Projects The High Level Reliability Standards Status Report, Addendum 1: Additional Information for Selected Projects contains information on projects that have a FERC filing deadline or a NERC Board of Trustees (Board) requested action. The addendum provides information regarding the project, potential issues and options for proceeding. The projects, and the reason each one was included in this report, are:

• Project 2008-06 Cyber Security Order 706 (CIP V5) – March 2013 FERC Filing Requirement

• Project 2007-02 COM-003-1 Operating Personnel Communications Protocols – Board Requested Action

• Project 2007-12 Frequency Response/BARC – May 2013 FERC Filing Requirement

• Project 2010-11 TPL footnote b – February 2013 BOT Presentation Requirement

• Project 2007-03 Real-time Transmission Operations (approved TOP standards) – Board Requested Information

Additionally, Addendum 1 provides a status update for Project 2013-02, Paragraph 81 Phase I. Reliability Standards Status Report The Reliability Standards Status Report for the Member Representatives Committee includes:

1. A report on the reorganization of the NERC Standards Department

2. Forecast of project presentations to the Board for adoption

3. An update for Regulatory Directives

4. The Standards Committee report

5. Report on regional standards

6. Discussion of the 2013 Work Plan

The Reliability Standards Development Plan is being developed in conjunction with the overall review of the standards development process. The high level areas of work to be addressed by the plan are provided in the “Discussion of the 2013 Work Plan” section. Enclosed Attachment

1. Reliability Standards Member Representatives Committee Status Report, November 6, 2012

If you have questions or need additional information, please contact Vice President and Director of Standards Mark Lauby at [email protected].

http://www.nerc.com/filez/standards/Real-time_Operations_Project_2007-03.html�


3353 Peachtree Road NE Suite 600, North Tower

Atlanta, GA 30326 404-446-2560 | www.nerc.com

Reliability Standards Member Representatives Committee Status Report

November 6, 2012

SOTC Quarterly Status Report – November 6, 2012 ii

Ta b le o f Con t e n t s Table of Contents .............................................................................................................................ii

Standards Organization................................................................................................................... 1

Standards Development Forecast (Continent-wide) ...................................................................... 2

Board of Trustees (Board) Meetings Forecast ............................................................................ 2

November 2012 ...................................................................................................................... 2

December 2012 ....................................................................................................................... 2

February 2013 ......................................................................................................................... 2

May 2013 ................................................................................................................................ 2

Additional Information for Selected Projects – See Addendum 1 .......................................... 3

Regulatory Directives — Update .................................................................................................... 4

Standards Committee Report ......................................................................................................... 5

Regional Standards Group October 2012 Report ........................................................................... 6

Regional Standards Activity–2012 .............................................................................................. 6

Regional standards and variances filed by NERC with FERC ................................................... 6

Regional standard adopted by the NERC Board with filings under development for FERC and the applicable Governmental Authorities in Canada ...................................................... 6

Regional standards and variances approved by Regional Entity Board (not included above) 6

Regional Standards in Process .................................................................................................... 6

2012 ............................................................................................................................................ 6

2013 ............................................................................................................................................ 6

2013 Work Plan ............................................................................................................................... 7

Addendum 1 .................................................................................................................................... 8

Additional Information for Selected Projects ................................................................................. 8

2008-06 Cyber Security Order 706 (CIP V5) – March 2013 Filing Requirement ......................... 8

SOTC Quarterly Status Report – November 6, 2012 iii

Potential Issues ....................................................................................................................... 8

Option for Proceeding ............................................................................................................. 8

Project 2007-02 – COM-003-1 Operating Personnel Communications Protocols – Board Requested Action ........................................................................................................................ 8

Potential Issues ....................................................................................................................... 9

Proceeding with COM-001 and COM-002 ............................................................................ 10

Options for Proceeding with COM-003 ................................................................................ 10

Frequency Response/BARC – May 2013 Filing Requirement ................................................... 11

Potential Issues ..................................................................................................................... 11

Options for Proceeding ......................................................................................................... 11

TPL footnote b - February 2013 Board Presentation Requirement ......................................... 12



TOP standards – BOT requested information ........................................................................... 13

Project 2007-03 - Real-time Transmission Operations ......................................................... 13



Project 2010-INT-01 Rapid Revision of TOP-006-2 in Response to FMPP's Request for Interpretation ........................................................................................................................ 14

Potential issues ..................................................................................................................... 14

Paragraph 81 Phase I – Status Update ..................................................................................... 15



Reliability Standards

1 SOTC Quarterly Status Report–November 6, 2012

Standards Organization

As part of NERC’s ongoing efforts to ensure the Standards Department increases its effectiveness enabling NERC to achieve the desired results, the Standards Department was reorganized. First, Valerie Agnew, Howard Gugel, and Laura Hussey now lead three Standards Development Teams. The goal of this re-alignment is to unlock the additional production potential from existing resources, along with adding additional resources as budgeted now and in 2013.

Further Kristin Iwanechko will lead a team responsible for Standards Information activities, key in the posting, balloting, and updating of NERC’s standards activities on NERC’s website. Below is an updated organizational chart, with new team assignments.

Mark Lauby Vice President and Director of Standards

Valerie Agnew Director of Standards

Development

Kristin IwanechkoManager of Standards

Information

Al McMeekinStandards Developer

Vacant Standards Developer

StandardsOctober 1, 2012

Howard GugelAssociate Director of

Standards Development

Laura HusseyDirector of Standards

Development

Edward DobrowolskiStandards Developer

Stephen Crutchfield Standards Developer

Suzanne Smith-WigfallExecutiveAssistant


Steven NoessStandards Developer

VacantStandards Developer

Joseph Krisiak Standards Developer

Scott Barfield-McGinnis Standards Developer

Darrel W. Richardson Standards Developer

Mark OlsenStandards Developer

Ryan StewartStandards Developer

Barbara Nutter Standards Developer

Laura AndersonStandards Developer

VacantStandards Developer

David TaylorDirector of Regulatory

Initiatives

Natara BierriaReliability Standards

Analyst

Monica Benson Standards Development

Administrator

Wendy KinnardStandards Development

Administrator


Mallory Huggins Standards Developer



Standards Development Forecast (Continent-wide)

Board of Trustees (Board) Meetings Forecast November 2012

• 2006-06 Reliability Coordination (COM-001 and COM-002)

• Project 2007-17 Protection System Maintenance and Testing – PRC-005-2

• Project 2009-01 Disturbance and Sabotage Reporting – CIP-001 and EOP-004

• Project 2010-INT-01 Interpretation of TOP-006-2

• Project 2009-19 Interpretation of BAL-002-0 R4 and R5

• Other: Standards Process Manual Revisions

• Other: Reliability Standards Development Plan December 2012

• 2008-06 Cyber Security Order 7061

February 2013

• 2007-02 Operating Personnel Communications Protocols - COM-003

• 2007-09 Generator Verification

• 2010-14.1 Phase 1 of Balancing Authority Reliability-Based Controls: Reserves (partial for BAL-012; remainder August 2013)

• 2007-12 Frequency Response

• Project 2010-11, TPL Footnote b

• Project 2013-02 Paragraph 81, Phase I

• Project 2012-INT-02 TPL-003-0a & TPL-004-0 for SPCS

• Other: VRF/VSL Revisions May 2013

• 2010-14.1 Phase 1 of Balancing Authority Reliability-Based Controls: Reserves (remainder)

• 2007-06 System Protection Coordination – PRC-027

• 2010-05.1 Phase 1 of Protection Systems: Misoperations2

1 See addendum 1 for additional project information.



August 2013

• Project 2010-13.2 Generator Reloadability

• Project 2010-17 DBES Phase 2 Additional Information for Selected Projects – See Addendum 1

• 2008-06 Cyber Security Order 706 (CIP V5) – March 2013 filing requirement

• Project 2007-02 – COM-003-1 Operating Personnel Communications Protocols – BOT requested action

• Frequency Response/BARC – May 2013 filing requirement

• TPL footnote b - February 2013 BOT presentation requirement

• TOP standards – BOT requested information

2 Rescheduled to the May BOT meeting to address comments received during the formal comment period and initial ballot that ended on September 7, 2012 with a 37.68% approval rating.



Regulatory Directives — Update

Summary of directive activity 2012 year-to-date:

Summary Standards-related directives as of January 1, 2012 272

(174 Directives from Order 693) Directives issued in 2012 year-to-date 11 Directives filed in 2012 year-to-date -20

Net 263 % Reduction Y-T-D 3.3%

Directives Issued in 2012 FERC Order 758 2

FERC Order 759 1 FERC Order 761 2 FERC Order 762 3 FERC Order 763 3

Total Y-T-D 11

Directives Filed or Completed in 2012 Compliance Filing for Order approving FAC-013-2 (Jan 17) 4

Project 2010-17 Definition of Bulk Electric System (Jan 25) 5 Regional (Feb 1) 1 Informational Filing of NERC in Response to Order 754 (Mar 15) 1 Informational Filing in Compliance with Order No. 758 (Apr 12) 1 Presentation to FERC Staff - Reliability Indicators (June 12) 1 Quarterly report on CIP Version 5 development (July 2) 1 Compliance Filing in Resp. to Order 763 (UFLS) 2 Resolved by NERC/FERC Coordination Effort (Closed #10026 and #10695: Deleted #10601 and #10274)

4

Total Y-T-D 20



Standards Committee Report This report highlights some of the key activities of the Standards Committee (SC) and its associated subcommittees in support of ERO Enterprise goals. The SC meets monthly and its meeting minutes are posted at http://www.nerc.com/filez/scmin.html. Standards Committee Strategic Vision and Workplan The SC has formed a small group to work with NERC staff to develop a strategic vision for the SC, which will be used to recommend governance and scope changes to better align the Committee’s work with ERO strategic direction. The SC expects to bring this strategic vision, and a work plan that will include metrics and specific milestones, to the Board in February 2013. Implementation of Standards Process Improvement Group (SPIG) Recommendations 1, 4, and 5 The SC is continuing to implement process improvements recommended by the Member Representatives Committee’s (MRC) SPIG to the Board in May. An initial ballot of revisions to the NERC Standard Processes Manual (Appendix 3A of NERC’s Rules of Procedure) concluded on October 12 and achieved a 63.17 percent approval and a 87.23 percent quorum. The SC and its subcommittees are analyzing stakeholder comments to identify opportunities to achieve consensus. In addition, the SC has identified revisions to certain documents that provide guidance to drafting teams as well as procedures that support the standards process. Work on the documents will be finalized after priorities are established in the strategic work plan. Reliability Standards Development Plan for 2013-2015 In support of developing the Reliability Standards Development Plan (RSDP) for 2013-2015, the SC solicited stakeholder input on new standards development projects for 2013-2015 as well as the prioritization of standards projects. Following these solicitations, the SC discussed three major initiatives for 2013 that collectively address the priorities included in the 2013 Work Plan section of this report. One or more SC members have been assigned to act as liaisons with each initiative.

The RSDP is being revised to incorporate these initiatives prior to filing with regulatory authorities. Cold Weather Preparedness To continue ERO efforts to address lessons learned from the February 2011 cold weather event, the SC posted a draft Standards Authorization Request (SAR) for stakeholder comment. The SAR will define the scope and intended reliability benefit of any standards development project. A SAR drafting team is being formed to review stakeholder comments and recommend revisions to the SAR to the SC. The SC chair has also nominated cold weather preparedness as a reliability risk issue for consideration by the Reliability Issues Steering Committee.



Regional Standards Group October 2012 Report The Regional Standards Group has been disbanded by order of the Executive Management Group. This report highlights the key activities of NERC and the Regions. Regional Standards Activity–2012 Regional standards and variances filed by NERC with FERC

• IRO-006-TRE-01 - IROL and SOL Mitigation in the ERCOT Region (TRE Regional Standard)

• PRC-006-SERC-01 - Automatic Underfrequency Load Shedding Requirements (SERC Regional Standard)

• PRC-006-NPCC-01 - Automatic Underfrequency Load Shedding (NPCC Regional Standard) Regional standard adopted by the NERC Board with filings under development for FERC and the applicable Governmental Authorities in Canada

• VAR-001-3 – Voltage and Reactive Control (WECC Variance) Regional standards and variances approved by Regional Entity Board (not included above)

• MOD-25-RFC-01 ReliabilityFirst (RFC) has requested NERC staff to delay filing this standard with FERC until a RFC Board directed evaluation of the need for regional standards is completed. RFC and NERC staff are recommending that the NERC BOT withdraw their approval of MOD-25-RFC-01 that was approved at the November 3, 2011 NERC BOT meeting and direct NERC staff to cease working on appropriate filings of MOD-25-RFC-01 with applicable regulatory authorities.

Regional Standards in Process 2012

• BAL-002-WECC-2

• PRC-006-SPP-01

• BAL-004-WECC-02

• BAL-001-1a WECC Variance 2013

• IRO-006-WECC-02



2013 Work Plan

Along with the current Standards Development Plan, which is being developed in conjunction with an overall review of the standards development process, NERC staff and the Standards Committee plan to address:

1. All remaining FERC Directives: An industry Standard Development Team will be requested to address the remaining directives. This will include categorization into high priority items, those already being addressed by the end of the year, and those that no action is required. The goal is to address these with one filing by the end of 2013.

2. Paragraph 81, Phase II: Complete the five year reviews and Paragraph 81 Phase II candidates. Phase I of the project identifies Reliability Standard requirements that clearly meet the criteria set forth in the SAR and do not require extensive technical research. Phase II will address Reliability Standard requirements that require additional technical research before retirement or modification. The goal is to seek Board approval of Phase I by February 2013 and Phase II by the end of 2013.

3. Finish remaining open standards projects: Establish milestones on all open projects for completion in 2013. Also review the prioritization of currently identified potential projects.

4. 2003 blackout report recommendations: Review and address recommendations made in the 2003 Blackout Report.



Addendum 1 Additional Information for Selected Projects

2008-06 Cyber Security Order 706 (CIP V5) – March 2013 Filing Requirement CIP Version 5 includes CIP-002-5 through CIP-009-5, CIP-010-1, and CIP-011-1. The project is committed to a FERC filing deadline of March 31, 2013 (imposed by FERC Order No. 761). Draft 3 of the project was posted for successive ballot from October 1 through October 10, 2012. All ballots passed, with approval ratings ranging from 74.85 percent to 94.00 percent. The anticipated schedule to complete the project is:

• Expected Recirculation: November 2012

• Expected Board consideration: December 2012 The third draft was enhanced to include the ability to correct CIP deficiencies in certain requirements to address the zero defect concerns expressed by commenters. Potential Issues The main concern for this standard is achieving the FERC filing deadline. Although success is not certain until the recirculation ballot is complete, the approval ratings for the successive ballot indicate that the recirculation ballots may pass. If the standard does not pass, there are two potential scenarios: 1) all 12 ballots receive at least a 2/3 approval rating during the recirculation ballot, in which case the filing date could be met or 2) one or more of the standards do not receive sufficient approval during the recirculation ballot. As all of the standards must be filed at the same time, even one not receiving approval could delay the project. Option for Proceeding In the event that one or more ballots do not receive a 2/3 or higher approval rating during the recirculation ballot, the BOT may determine if an expedited method for completing the standard is necessary in order to meet the deadline.

Project 2007-02 – COM-003-1 Operating Personnel Communications Protocols – Board Requested Action COM-003-1 addresses using communication protocols when issuing Operating Instructions.3

COM-003-1 is part of a communications package that includes COM-001-2 and COM-002-3.

3 Operating Instruction —Command from a System Operator to change or preserve the state, status, output, or input of an Element of the Bulk

Electric System or Facility of the Bulk Electric System.



The third draft of this standard incorporated an entity’s ability to correct deficiencies in certain requirements to address the zero defect concerns expressed by commenters. This, in essence, allows industry to find and correct deficiencies without compliance penalty, thereby creating established routines for entities to use for protocols in communications. This standard complements COM-002-3, which requires an entity to use three-part communication whenever an entity identifies a communication as a Reliability Directive.4

There is no imposed deadline for this project; however, in February 2012, when the NERC Board adopted the COM-002-2 interpretation, the Board requested that COM-003-1 be expedited:

“FURTHER RESOLVED, that the board directs the Standards Committee to complete developmental activities on proposed Reliability Standard COM-003 on a high priority basis; …”

The last successive ballot received a 50.57 percent approval rating and thus will require another formal comment period and ballot before it can go to the recirculation ballot. The current state is:

5. Drafting team met the week of October 1 to consider the comments received during the last comment period

6. Next expected formal comment period and ballot: October/November 2012

7. Recirculation: December 2012 or January 2013

8. Expected Board consideration: February 2013 Potential Issues The main concerns for this standard is 1) the time it may take to complete and file the COM package and 2) if the standard is not completed, whether COM-002-3 is sufficient for reliability without COM-003-1. The purpose of the COM-002-3 is “To ensure Emergency communications between operating personnel are effective.” However, the standard does not require any emergency communications be identified as a Reliability Directive unless action by the recipient is necessary to prevent or limit the failure of transmission facilities or generation supply that could adversely affect the reliability of the Bulk Electric System (BES) or address the impact of an event that results in BES instability or cascading. Thus, there may be very limited situations in which a registered entity identifies a communication as a Reliability Directive, leaving the majority of communications not subject to requirements to use either three-part communication or other communication protocols. Therefore, COM-002-3 may not be sufficient for reliability without COM-003-1.

4 Reliability Directive: A communication initiated by a Reliability Coordinator, Transmission Operator, or Balancing Authority where action by

the recipient is necessary to address an Emergency or Adverse Reliability Impact.



Proceeding with COM-001 and COM-002 Currently, NERC is seeking Board adoption of the proposed COM-001-2 and COM-002-3 standards and will file with regulatory authorities for approval after Board adoption.

Options for Proceeding with COM-003

1. The proposed COM-003 standard is proceeding through the standards development process and is anticipated to be presented to the Board for adoption at the February 2013 meeting. That standard will be filed with regulatory authorities for approval upon Board adoption.

2. If the COM-003 standard fails the industry ballot, based on the result, the BOT may determine if an expedited method for completing the standard is necessary.



Frequency Response/BARC – May 2013 Filing Requirement In Order No. 693 (March 2007), the Commission approved BAL-003-0 and directed NERC to develop a modification to BAL-003-0 through the Reliability Standards development process that “defines the necessary amount of Frequency Response needed for Reliable Operation for each balancing authority with methods of obtaining and measuring that the frequency response is achieved.” The standard drafting team (SDT) for Project 2007-12 is developing a revision to the BAL-003 standard that will address the first part of the directive (i.e., “define the necessary amount of Frequency Response needed for Reliable Operation for each Balancing authority”). The Project 2010-14.1 SDT is developing a proposed BAL-012-1 standard that will address the second part of the directive (i.e., “with methods of obtaining and measuring that the frequency response is achieved.”). The deadline for responding to the Order No. 693 directives is May 31, 2013. Both SDTs are on schedule to deliver to the Board no later than its May 9, 2013 meeting. Potential Issues The primary concern is whether the standards will achieve necessary industry consensus in order for NERC to meet the FERC filing deadline. NERC has been working on developing a Frequency Response Standard since 2007 and is currently under a Commission deadline to file a revised standard by no later than May 31, 2013. Options for Proceeding The standards are expected to be approved through the existing process and the scheduled ballots. If the necessary consensus is reached by the final ballot, NERC staff will present the draft standard(s) to the Board for approval at the May 9, 2013 Board meeting and file them with FERC by the May 31, 2013 deadline. In the event that the successive ballots do not receive a 2/3 or higher approval rating, the BOT may determine if an expedited method for completing the standard is necessary in order to meet the deadline.



TPL footnote b - February 2013 Board Presentation Requirement On April 19, 2012, FERC issued Order No. 762 remanding NERC’s proposed Transmission Planning (TPL) Reliability Standard TPL-002-2b. The TPL-002-2b standard includes a provision (footnote b) that provides for planned load shed for a single contingency provided that the plan is documented and alternatives are considered and vetted in an open and transparent stakeholder process. In its remand, the Commission determined that the proposed footnote is vague, unenforceable, and not responsive to the directives. The Project 2010-11, TPL Table 1, footnote b standard drafting team is revising footnote b responsive to Order No. 762. The initial comment and ballot (last 10 days of comment period) is scheduled for October 5 through November 19. There is no regulatory deadline to respond to Order No. 762. However, NERC has committed to filing a revised footnote b by February 2013. To meet this deadline, in order to complete the balloting process, the time period will be reduced from the usual 30 days to 15 days. Assuming approval of the revised footnote b, NERC staff will ask the Board for approval at the February 7, 2013 meeting. Potential Issues The primary challenge is to achieve the necessary industry consensus for the revised footnote b to meet the target filing date of February 2013. To meet the NERC schedule, there is no time for additional ballots beyond those included in the project schedule. Options for Proceeding The standards are expected to be approved through the existing process and the scheduled ballots. If the necessary consensus is reached by the final ballot, NERC staff will present the revised footnote b to the Board for approval at the February 9, 2013 meeting, and file with the Commission by the end of February. If the revised footnote b does not achieve the necessary consensus by February 2013, the BOT may determine if an expedited method for completing the standard is necessary in order to meet the deadline.



TOP standards – BOT requested information Project 2007-03 - Real-time Transmission Operations At its May 2012, the Board approved the following proposed reliability standards and Implementation Plan addressed in Project 2007-03:

• Reliability Standard TOP-001-2 Transmission Operations, effective consistent with the Implementation Plan for Project 2007-03;

• Reliability Standard TOP-002-3 Operations Planning, effective consistent with the Implementation Plan for Project 2007-03;

• Reliability Standard TOP-003-2 Operational Reliability Data, effective consistent with the Implementation Plan for Project 2007-03;

At the time of approval, the BOT asked NERC staff to review the TOP standards with regards to Interconnection Reliability Operating Limits (IROLs) and ensuring that the lessons learned from the Pacific Southwest blackout were addressed by the standards. Potential Issues The main question for these standards is whether the newly approved standards meet or exceed the currently effective TOP standards in supporting the reliability of the bulk power system, based on lessons learned from the Pacific Southwest blackout. In the event it is determined the newly approved TOP standards should be remanded for additional work due to identified reliability gaps, the delay in the regulatory filing would also delay the regulatory filing of the Board approved IRO standards. NERC is currently conducting an internal review to determine if any reliability gaps are identified. Options for Proceeding

1. If it is determined that no reliability gaps are created by the newly approved TOP standards, proceed with the regulatory filing.

2. If it is determined that reliability gaps are created by the newly approved TOP standards, either:

• Proceed with the regulatory filing and propose a phase 2 to address the reliability gaps, or

• Request the Board to remand the TOP standards for additional work and hold the regulatory filing of the IRO standards pending subsequent approval of the revised TOP standards.



Project 2010-INT-01 Rapid Revision of TOP-006-2 in Response to FMPP's Request for Interpretation A related issue is the revision of TOP-006-2, which addressed two questions originally raised through the interpretation process:

• For Requirement 1.2, since the Balancing Authority (BA) is not responsible for transmission, is the BA responsible for reporting generation resources available for use and is the Transmission Operator (TOP) responsible for reporting transmission resources that are available for use?

• For Requirement 3, does “appropriate technical information concerning protective relays” refer to protective relays for which the entity has responsibility?

Potential issues There are two existing Compliance Application Notices (CANs) on the topics covered by these revisions. CAN-0026 addresses protective relay information referenced in Requirement R3, and CAN-0028 addresses the reporting responsibilities of the TOPs and BAs referenced in Requirement R1.2. Proposed TOP-006-3 differs from CAN-0026 in that it specifies entities need to provide technical information for protective relays within their respective areas, whereas the CAN, based on TOP-006-2, specifies that the Compliance Enforcement Authority (CEA) will assess compliance based on whether the entity provided technical information for protective relays that may impact the RC, TOP, or BA, regardless of whether the entity has ownership or maintenance responsibility for those relays. Proposed TOP-006-3 differs from CAN-0028 in that reporting responsibilities differ. The proposed standard provides that BAs report generating resources available for use to the RC; the CAN, based on TOP-006-2, specifies that the CEA will assess compliance based on whether the entity also provided reporting to other affected BAs and TOPs. Regarding TOPs, the standard requires reporting to the RC and other affected TOPs; the CAN specifies that the CEA will assess compliance based on whether the entity also provided reporting to other affected BAs. This project was pursued in parallel with a larger project (Project 2007-03) that is revising the suite of TOP standards and which addresses the issues in question.

http://www.nerc.com/filez/standards/2010-INT-01_Interpretation_TOP-006-2_FMPP.html�

http://www.nerc.com/filez/standards/2010-INT-01_Interpretation_TOP-006-2_FMPP.html�



Pa ra g ra p h 8 1 Ph a se I – St a t u s Up d a t e In its March 15, 2012 FFT Order, the Commission provided an opportunity for the ERO to examine its standards and “…remove from the Commission-approved Reliability Standards unnecessary or redundant requirements.” A collaborative core team including NERC, the Regional Entities and industry, as represented by the Trade Organizations,5

was formed to identify potential requirements to be candidates for retirement. This team developed criteria for determining which requirements were appropriate. The core team 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 extensive technical research. The core team set a target date for filing Phase I with FERC by the end of 2012.

Based on the criteria, 79 potential requirements were initially identified, 11 of which were under consideration for retirement in current drafting projects. The Paragraph 81 drafting team, in response to industry comments to the draft Standard Authorization Request (SAR), conducted additional research on the identified standards to ensure that requirements included in Phase I clearly met the criteria and would pass muster with industry and regulators (FERC and the Canadian Provinces). It was determined that 38 requirements clearly met the criteria and will be posted for a formal comment period and balloted. The remainder of the 79 requirements, plus others, will be included in the second phase of the project, where additional technical research will be conducted prior to the requirements being proposed for retirement. Additionally, modifications to requirements may be included. Potential Issues There are no concerns regarding this project other than a sense of urgency to complete the project. The project was posted during the week of October 15 for an initial comment period and ballot. Options for Proceeding The project is posted for an initial comment period from mid October through the beginning of December. Depending upon the ballot results, the project will either:

• Be posted for recirculation ballot. In the event that the project is approved and depending upon the timing of the recirculation ballot, the project may be presented to the BOT at the December meeting.

• Be posted for a successive ballot. In this scenario, it is anticipated that the project would be presented to the BOT at the February meeting.

5 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


Adequate Level of Reliability (ALR) Definition and Technical Report Action Discussion of the following documents:

• [Definition of Adequate Level of Reliability: Clean]

• [Technical Report Supporting Definition of Adequate Level of Reliability: Clean] Background The Adequate Level of Reliability Task Force (ALRTF) was formed in May 2011 under the auspices of the Standing Committees’ Coordination Group (SCCG) to address concerns expressed by the NERC Board of Trustees, the Member Representatives Committee (MRC), and stakeholders about NERC’s current definition of Adequate Level of Reliability (ALR).1

The MRC/Bulk Electric System (BES) policy input group provided guidance addressing three key issues: 1) load loss distinctions; 2) cost/benefit; and 3) the definition of cascading.2 A link to the project history and files, including responses to stakeholder comments from the two comment periods, and a document with final remarks from the ALRTF is included here for reference: Adequate Level of Reliability Task Force Project Page. The goal of the ALRTF3

was to develop a definition of ALR that encompasses NERC’s responsibility to ensure reliable planning and operation of the BES, along with the obligation to assess the capability of the BES. The definition developed by the ALRTF identifies and defines Reliability Performance Objectives that drive the activities of system planners and operators to ensure that the BES is reliable. Further, the enhanced definition outlines Reliability Assessment Objectives that identify risks to system reliability.

The ALRTF determined that soliciting wide stakeholder feedback in addition to feedback from the SCCG was important. Therefore, the ALRTF elected to conduct two stakeholder comment periods: an initial 60-day stakeholder comment period from April 25 through June 25, 2012, and a second 30-day stakeholder comment period from August 15 through September 13, 2012. If there are any questions or if additional information is needed, please contact Mark Lauby, vice president and director of standards, at [email protected].

1 http://www.nerc.com/docs/standards/Adequate_Level_of_Reliability_Defintion_05052008.pdf. 2 http://www.nerc.com/docs/standards/AgendaItem_13-attach-1.pdf. 3 Draft scope at http://www.nerc.com/docs/standards/Attachment%202_ALR%20TF_DRAFT_Scope%20-V5_Clean.pdf.

http://www.nerc.com/docs/standards/10_04_12_ALR_Definition_clean.pdf�

http://www.nerc.com/docs/standards/10_04_Technical_Report_ALR_clean.pdf�

http://www.nerc.com/filez/alrtf.html�


http://www.nerc.com/docs/standards/Adequate_Level_of_Reliability_Defintion_05052008.pdf�

http://www.nerc.com/docs/standards/AgendaItem_13-attach-1.pdf�

http://www.nerc.com/docs/standards/Attachment%202_ALR%20TF_DRAFT_Scope%20-V5_Clean.pdf�

The “predefined Disturbances” in Performance Objectives 1-3 and Assessment Objectives 1 and 2 are the more probable Disturbances to which the power system is planned, designed and operated. These Disturbances have a higher probability of occurring than other severe, low probability events; BES Facilities are designed and operated to withstand these Disturbances. An example of a predefined Disturbance is the loss of a Transmission circuit due to a lightning strike.

Definition: Adequate Level of Reliability for the Bulk Electric System

Definition ALR is the state that the design, planning and operation of the Bulk Electric System (BES) will achieve when the listed Reliability Performance Objectives are met. Further, Reliability Assessment Objectives included in the definition must be evaluated to assess reliability risk in support of an adequate level of reliability.

ALR Performance Objectives

1. The BES does not experience instability, uncontrolled separation, Cascading1 or voltage collapse under normal operating conditions and when subject to predefined Disturbances.2 The performance outcomes are:

Stable frequency and voltage within predefined ranges

No instability, uncontrolled separation, Cascading or voltage collapse

1 NERC’s Glossary of Terms defines Cascading as: “The uncontrolled successive loss of system elements triggered by an incident at any location. Cascading results in widespread electric service interruption that cannot be restrained from sequentially spreading beyond an area predetermined by studies.” 2 NERC’s Glossary of Terms defines Disturbance as: “1. An unplanned event that produces an abnormal system condition. 2. Any perturbation to the electric system. 3. The unexpected change in ACE that is caused by the sudden failure of generation or interruption of load.

Purpose Statement: The definition of Adequate Level of Reliability (ALR) will be used primarily to guide NERC Reliability Standards development, but also by the NERC Performance Analysis Subcommittee and NERC reliability assessment staff to assess BES reliability and identify gaps in data. Other NERC groups, such as the Reliability Issues Steering Committee, will be able to use the document for guidance when addressing major reliability issues and prioritizing work. The definition and its supporting technical report should not be interpreted as requiring the development of specific standards or additional compliance elements. Both the definition and the technical report will be filed for information with FERC.

Definition: Adequate Level of Reliability for the Bulk Electric System October 3, 2012 2

The Disturbances in Performance Objectives 4 and 5 cannot be predefined. For these less probable severe events, BES owners and operators may not be able to apply any economically justifiable or practical measures to prevent or mitigate their Adverse Reliability Impact on the BES despite the fact that these events can result in Cascading, uncontrolled separation or voltage collapse. For this reason, these events generally fall outside of the design and operating criteria for BES owners and operators. Less probable severe events would include, for example, losing an entire right of way due to a tornado or hurricane, or simultaneous or near simultaneous multiple Transmission Facilities outages due to geomagnetic Disturbances.

2. BES frequency is maintained within defined parameters under normal operating conditions and when subject to predefined Disturbances.

The performance outcomes are:

Stable frequency within predefined range

Facility Ratings respected

Frequency oscillations experience positive damping

3. BES voltage is maintained within defined parameters under normal operating conditions and when subject to predefined Disturbances. The performance outcomes are:

Stable voltage within predefined range

Facility Ratings respected

Voltage oscillations experience positive damping

4. Adverse Reliability Impacts3 on the BES following low probability Disturbances (e.g., multiple contingences, unplanned and uncontrolled equipment outages, cyber security events and malicious acts) are managed.

The performance outcome is to manage the propagation of frequency, voltage, or angular instability, uncontrolled separation, or Cascading.

5. Restoration of the BES after major system Disturbances, such as blackouts and widespread outages, is performed in a coordinated and controlled manner. The performance outcome is to recover the BES and restore available resources and load to a stable interconnected operating state expeditiously after a major system Disturbance.

3 NERC’s Glossary of Terms defines Adverse Reliability Impact as “The impact of an event that results in Bulk Electric System instability or Cascading.”


ALR Assessment Objectives

“Adequate level of reliability” is a term used in Section 215 (c)(1) of the Federal Power Act, specifying what standards the electric reliability organization (ERO) can develop and enforce. Section 215 specifically does not authorize the ERO to develop standards related to adequacy and safety. However, this definition of ALR is meant to encompass all the duties of the ERO, including obligations to perform assessments of resource and Transmission4 adequacy.

A target to achieve adequate Transmission transfer capability and resource capability to meet forecast demand is an inherent, fundamental objective for planning, designing and operating the BES. The Assessment Objectives do not suggest that NERC Reliability Standards mandate that such additions be developed; they are not directly related to NERC’s standards development and enforcement activities.

1. BES Transmission capability is assessed to determine availability to meet anticipated BES demands during normal operating conditions and when subject to predefined Disturbances.

The outcome is that assessment results are available to provide situational awareness for appropriate actions.

2. Resource capability is assessed to determine availability to the BES to meet anticipated BES demands during normal operating conditions and when subject to predefined Disturbances.

The outcome is that assessment results are available to provide situational awareness for appropriate actions.

Time Periods and Performance Outcomes In the associated technical report supporting this definition, performance outcomes associated with each Reliability Objective are addressed in further detail based on four time frames:

Steady State – Time period before a Disturbance occurs and after system restoration has achieved normal operating conditions. It is a stable pre-event condition for the existing system configuration, which includes all existing BES elements, including elements on planned outage for maintenance, construction or safety purposes or unplanned outage. Transient – Transitional time period beginning after a Disturbance in which high-speed automatic actions occur in response to the Disturbance. This time period starts at the time of the Disturbance and can continue for seconds or until a new steady state is achieved.

4 NERC’s Glossary of Terms defines Transmission as: “An interconnected group of lines and associated equipment for the movement or transfer of electric energy between points of supply and points at which it is transformed for delivery to customers or is delivered to other electric systems.”


Operations Response – Time period after a Disturbance during which some automatic actions occur and operators act to minimize the impact of Disturbances and return the BES to a new steady state, if possible. This state may begin seconds after the Disturbance and continue for hours. Recovery and System Restoration – Time period after a widespread outage or blackout occurs, through the initial restoration to a sustainable operating state, and recovery to a new steady state that meets reliability objectives established by the circumstances of the Disturbance.

Technical Report Supporting Definition of Adequate Level of Reliability The associated technical report describes the relationship among Reliability and Assessment Objectives, performance outcomes, and Disturbances in greater detail. The report also provides some examples of means to meet Reliability Objectives. Reviewed together, these items provide the tools for both understanding and achieving an adequate level of reliability.


Discussion of Proposed Revisions to the Technical Feasibility Exception Process

in the NERC Rules of Procedure, Appendix 4D Posted for Public Comment

Action Discuss input from the Member Representatives Committee on the proposed revisions to the Technical Feasibility Exception Process in the NERC Rules of Procedure, Appendix 4D that were posted for public comment on October 5, 2012. Background The North American Electric Reliability Corporation (NERC) is proposing amendments to the NERC Rules of Procedure (ROP) in Appendix 4D. The proposed amendments are posted for public comment from October 5, 2012 to November 19, 2012. An industry webinar will be held on October 31, 2012. If approved by the NERC Board of Trustees (Board) during its December 19, 2012 conference call, the amendments will be filed with the appropriate regulatory authorities for approval. Discussion The Regional Entities and NERC have worked collaboratively to develop proposed revisions to Appendix 4D to the ROP to streamline the process for approving technical feasibility exceptions (TFEs) to Critical Infrastructure Protection (CIP) Reliability Standards. The proposed revisions to Appendix 4D represent a significant improvement to the current TFE process that will allow resources to be refocused on activities that can directly impact reliability, and decrease administrative tasks. The Regional Entities have led the efforts to review and restructure the TFE process since January 2012. The goal was to evaluate and realign the burden and benefits associated with the TFE process. Over a period of several months, the technical experts at each Regional Entity developed the initial concept for streamlining the TFE process. Certain Regional Entities also presented the streamlining proposal to various industry stakeholders in trade conferences and meetings. Throughout the process, industry stakeholders have provided feedback, suggestions, and concerns, which were considered as the proposal was refined. There is broad support for the streamlining concept. NERC staff and the Regional Entities worked to develop the specific proposed changes to Appendix 4D attached hereto, which were most recently discussed with industry representatives during an in person meeting at NERC in October 2012, ahead of the posting period. The proposed revisions to Appendix 4D draw upon the experience gained to date by the Regional Entities’ staff tasked with processing large numbers of TFE requests during the last two years. When Appendix 4D was originally developed, Regional Entities and registered entities had minimal experience as to the types of issues that would arise in connection with TFE requests, including associated risks and vulnerabilities, and the amount and nature of information needed to substantiate TFE requests. Experience has shown that the majority of

the TFE requests relate to low-risk issues, have common rationales and justification, are supported by common evidence, and often involve similar devices across registered entities nationwide. Because of this experience, the administrative burden associated with the current process is no longer justified when weighed against the benefits to reliability afforded by the current process. Enclosed Attachments

1. Detailed summary of the proposed amendments on a section-by-section basis

2. Full redline of the proposed amendments

3. Notice of proposed revisions to NERC Rules of Procedure Appendix 4D and request for comments

1

Summary of Proposed Revisions to the Technical Feasibility Exception Process in the NERC Rules of Procedure, Appendix 4D

The North American Electric Reliability Corporation (NERC) is proposing amendments to the NERC Rules of Procedure (ROP) in Appendix 4D. If approved by the NERC Board of Trustees (BOT), these amendments will be filed with the appropriate regulatory authorities for approval. A detailed summary of the proposed amendments on a section-by-section basis is provided. Additionally, this document includes a description of outreach efforts associated with these proposed changes. Background The Regional Entities and NERC have worked collaboratively to develop proposed revisions to Appendix 4D to the NERC Rules of Procedure to streamline the process for approving technical feasibility exceptions (TFEs) to Critical Infrastructure Protection (CIP) Reliability Standards. The proposed revisions to Appendix 4D represent a significant improvement to the current TFE process that will allow resources to be refocused on activities that can directly impact reliability, and decrease administrative tasks. The Regional Entities have led the efforts to review and restructure the TFE process since January 2012. The goal was to evaluate and realign the burden and benefits associated with the TFE process. Over a period of several months, the technical experts at each Regional Entity developed the initial concept for streamlining the TFE process. Certain Regional Entities also presented the streamlining proposal to various industry stakeholders in trade conferences and meetings. Throughout the process, industry stakeholders have provided feedback, suggestions, and concerns, which were considered as the proposal was refined. There is broad support for the streamlining concept. NERC staff and the Regional Entities worked to develop the specific proposed changes to Appendix 4D attached hereto, which were most recently discussed with industry representatives during an in person meeting at NERC in October 2012, ahead of the posting period. The proposed revisions to Appendix 4D draw upon the experience gained to date by the Regional Entities’ staff tasked with processing large numbers of TFE requests during the last two years.1

1 Over the first several months of the program, more than 5,000 TFE requests were submitted. See Annual Report of the North American Electric Reliability Corporation on Wide-Area Analysis of Technical Feasibility Exceptions, Docket No. RR10-1-001 (September 28, 2011).

When Appendix 4D was originally developed, Regional Entities and registered entities had minimal experience as to the types of issues that would arise in connection with TFE requests, including associated risks and vulnerabilities, and the amount and nature of information needed to substantiate TFE requests. Experience has shown that the majority of the TFE requests relate to low-risk issues, have common rationales and justification, are supported by common evidence, and often involve similar devices across registered entities nationwide. Because of this experience, the administrative burden associated with the current process is no longer justified when weighed against the benefits to reliability afforded by the current process.

2

Principal Revisions The principal feature of the proposed revisions is the elimination of the two-phased (Part A and Part B) TFE request. Currently, the TFE request process includes a preliminary screening phase (Part A) and a substantive review phase (Part B). Regional Entities have accumulated a significant database of materials used to justify TFE requests and compensating and mitigating measures. Because many types of TFE requests and related substantiation materials are similar in nature, Regional Entities are currently able to consolidate the two phases in the current process into one simplified step for gathering the information associated with a TFE request. In addition, the proposal shortens the overall processing time for TFE requests (from approximately 13 months to 4 months), including the processing time for amending a pending or existing TFE request. The proposal also eliminates the periodic reporting requirements applicable to registered entities and replaces them with a Material Change Report to be submitted as necessary. The proposal addresses primarily the processing of TFEs. No changes to the criteria for approving TFEs are being proposed, although the method for analyzing whether the existing criteria has been met is modified as indicated above. The requirements related to the development of compensating and mitigating measures are not affected. The availability of a safe harbor period during the pendency of the request and for a subsequent period, in the event of a disapproved TFE, also remains. Finally, the proposed changes will continue to ensure that sufficient information associated with TFE requests remains available to NERC and the appropriate regulatory authorities. Section-by-Section Revisions Section 2.11 – References to “rejecting” and “rejection” of a TFE request were deleted in this section and throughout the document to reflect the consolidation of the screening and substantive review phases of the TFE process. Under the proposed revisions, TFE requests would no longer be subject to acceptance or rejection but rather approval or disapproval. New sections 2.17 and 2.18 – The defined terms “Material Change” and “Material Change Report” were added to reflect a streamlined reporting requirement for changes to an approved TFE request. Old sections 2.19 and 2.20 – The defined terms “Part A Required Information” and “Part B Required Information” were deleted to reflect the new format of the TFE request, which is consolidated into a single submittal. Section 3.4 – This section was revised to reflect the new process for modifying an approved TFE through a Material Change Report. Section 4.1 – This section was revised to reflect the possibility of submitting class-based TFE requests. In addition, language was deleted to allow Regional Entities to collaborate on approval of TFE requests for entities located in multiple Regional Entity footprints.

3

Sections 4.2 and 4.3 – These sections were revised to reflect the new format and Required Information associated with a TFE request. While the amount of information to be submitted is greatly reduced, the Regional Entity retains the ability to seek any other information that may be necessary or appropriate. In addition, the new language authorizes the Regional Entity to verify any information at a subsequent audit, spot check or other form of compliance monitoring. The TFE request would no longer involve a initial screen followed by a substantive review (former Parts A and B). Rather, the review would be performed on the basis of the consolidated TFE request, with substantiation to follow through a compliance monitoring and enforcement program (CMEP) process. Section 4.4.1 – This section was revised to reflect the elimination of Part B of the TFE Request. Section 4.5 – This section as revised to reflect the elimination of the initial screening (Part A) process. Sections 5.0 and 5.1 – The headings of the sections were modified to reflect the elimination of the screening process and consequent acceptance or rejection. Sections 5.1.1, 5.1.3-5.1.7 – These sections were revised to reflect the elimination of the Part A submittal as well as the streamlined information requirements and consolidated review and approval process for TFE requests. Section 5.2.1 – This section was revised to reflect the elimination of the Part B submittal. In addition, the reference to Data Request was eliminated as unnecessary since CMEP processes rather than Data Requests are generally used in connection with TFE reviews. Section 5.2.2 – This section was revised to eliminate a cross reference to a deleted section. Section 5.2.3 – This section was revised to reflect that a TFE request can be approved in part. Section 5.2.5 – This section was revised to reflect that the primary responsibility for supporting a TFE request rests with the Responsible Entity. While the Regional Entities could discuss potential revisions with the Responsible Entity, the Responsible Entity is the entity with the information needed to develop any necessary revisions. Sections 5.2.8 and 5.2.9 – These sections were revised to reflect the consolidation of the review process and the elimination of initial screening phase, in which the TFE request could be “rejected.” Section 5.3 – This section was revised to reflect the consolidation of the review process and the elimination of initial screening phase, in which the TFE request was “accepted” for further review and approval or “rejected.” Section 6.2 – This section was modified to recognize that the majority of the TFE requests do not have Expiration Dates. Experience has shown that most TFEs relate to network devices and other equipment for which vendors are not pursuing versions that would allow Strict Compliance

4

with NERC Reliability Standards and consequently, a need for an open-ended TFE exists in most cases. Section 6.3 and 6.4 – These sections were deleted to eliminate the requirements for quarterly reports to the Regional Entity. Experience has demonstrated that these are not necessary to maintain reliability so long as the TFE remains unchanged. Under section 13.5, however, both Regional Entities and Responsible Entities remain under the obligation to provide any information deemed necessary for NERC to fulfill its reporting obligations to FERC, and Responsible Entities have the obligation to notify Regional Entities in any Material Changes to TFEs Section 6.5 – This section was modified to eliminate the requirement for an annual report to the Regional Entity and instead require a Material Change Report that would be submitted when an amendment to the initial TFE request occurs. Under section 13.5, both Regional Entities and Responsible Entities remain under the obligation to provide any information deemed necessary for NERC to fulfill its reporting obligations to FERC. Section 6.6 – This section was modified to reflect the requirement of a Material Change Report and the elimination of the quarterly and annual reports to the Regional Entity. Section 6.9 – This section was modified to eliminate the requirement for a report to be submitted thirty days prior to the Expiration Date. Section 7.1 – This section was modified to revise the process for changes to appending TFE request. A Responsible Entity may make any necessary changes without restarting the TFE request process during the first sixty days of review. At the end of the sixty-day period, the Regional Entity will approve or disapprove the TFE request with the information available to it unless the Regional Entity determines that it needs additional time. This modification is necessary to encourage complete submittals and discourage unnecessary amendments or revisions to the request that could delay the processing of the TFE request. Section 7.2.1 and 7.2.2 – These sections were modified to reflect the elimination of the Part A and B phases of the process. Section 7.2.3 – This section was deleted to reflect the changes to the amendment process. Section 8.1 – This section was revised to allow, instead of require, that a Regional Entity conduct an audit following the approval of every TFE request. The Regional Entities should retain flexibility to determine audit schedules in connection with a number of factors, only one of which would be the verification of issues associated with TFE requests. Experience has demonstrated that a number of TFE requests involve matters of low risk for which the rationales, evidence, documentation, and compensating and mitigating measures are uniform and familiar to Regional Entities and Responsible Entities alike. In some cases, verification in an audit may not be necessary.

5

Section 9.1 – This section was revised to clarify the circumstances in which a TFE would be terminated. Section 10.0 – This section has been deleted as the process is duplicative of the process for appealing Possible Violations. Section 11.2 – This section was revised to eliminate a process that has not proven particularly useful in the context of NERC’s and the Regional Entity’s review of consistency in the approval and disapproval of TFE requests. Other steps, which remain in section 11.2, have been more effective in pursuing this objective. Section 12.0 – This section has been revised to reflect the elimination of the Part A and B phases of the TFE process. Section 13.2 – This section has been deleted to eliminate the requirement of a quarterly report to NERC. It is noted, however, that both Regional Entities and Responsible Entities remain under the obligation to provide any information deemed necessary for NERC to fulfill its reporting obligations to FERC.

WORKING DRAFT – 10/05/12 Posting

PROCEDURE FOR REQUESTING AND RECEIVING

TECHNICAL FEASIBILITY EXCEPTIONS

TO NERC CRITICAL INFRASTRUCTURE PROTECTION STANDARDS

APPENDIX 4D TO THE RULES OF PROCEDURE

Effective: January 31, 2012[DATE]

Appendix 4D - Technical Feasibility Exception Procedure

Effective: January 31, 2012 -i-

TABLE OF CONTENTS [TO COME] 1.0. INTRODUCTION 1 1.1. Purpose 1 1.2. Authority 1 1.3. Scope 1 1.4 Obligations of Canadian Entities and Cross-Border Regional Entities 2 2.0. DEFINITIONS 2 3.0. BASIS FOR APPROVAL OF A TECHNICAL FEASIBILITY EXCEPTION 4 4.0. FORM, CONTENTS AND SUBMISSION OF A TFE REQUEST 6 4.1 Separate Submission for Each TFE Request 6 4.2 Form and Format of TFE Request 6 4.3 Required Information to be Included in the TFE Request 7

4.4 Access to Confidential Information, Classified National Security Information, NRC Safeguards Information, and Protected FOIA Information Included in Required Information 10

4.5 Submission of TFE Request in Advance of Compliant Date 11

5.0. REVIEW, ACCEPTANCE/REJECTION AND APPROVAL/DISAPPROVAL OF TFE REQUESTS 11 5.1 Initial Screening of TFE Request for Acceptance 11

5.2 Substantive Review of TFE Request for Approval or Disapproval 13 5.3 No Findings of Violations or Imposition of Penalties for Violations of an Applicable Requirement for the Period a TFE Request is Being Reviewed 16

6.0 IMPLEMENTATION AND REPORTING BY THE RESPONSIBLE ENTITY PURSUANT TO AN APPROVED TFE 17 7.0 AMENDMENT OF A TFE REQUEST OR APPROVED TFE 18


Effective: January 31, 2012[DATE] -ii-

7.1 Amendment of a Pending TFE Request 18 7.2 Amendment of an Approved TFE 18 8.0 COMPLIANCE AUDIT REQUIREMENTS RELATING TO APPROVED TFE 19 9.0 TERMINATION OF AN APPROVED TFE REQUEST 19 10.0 HEARINGS AND APPEAL PROCESS FOR RESPONSIBLE ENTITY 20 11.0 CONSISTENCY IN APPROVAL AND DISAPPROVAL OF TFE REQUESTS 20 12.0 CONFIDENTIALITY OF TFE REQUESTS AND RELATED INFORMATION 22 13.0 ANNUAL REPORT TO FERC AND OTHER APPLICABLE GOVERNMENTAL AUTHORITIES 23 13.1 Contents of Annual Report 23 13.2 Submission of Quarterly Reports by Regional Entities to NERC 24 13.3 Due Date for Annual Reports 25 13.4 Annual Report to be a Public Document; Confidential Appendix 25 13.5 Responsible Entities Must Cooperate in Preparation of Annual Report 25


Effective: January 31, 2012 -1-

PROCEDURE FOR REQUESTING AND RECEIVING TECHNICAL FEASIBILITY EXCEPTIONS

TO NERC CRITICAL INFRASTRUCTURE PROTECTION STANDARDS 1.0 INTRODUCTION 1.1. Purpose This Appendix to the Rules of Procedure of the North American Electric Reliability Corporation (NERC) provides the procedure by which a Responsible Entity may request and receive an exception from Strict Compliance with the terms of a Requirement of certain NERC Critical Infrastructure Protection (CIP) Standards on the grounds of technical feasibility or technical limitations. Such an exception is referred to herein as a Technical Feasibility Exception (TFE). This Appendix is intended to implement authorization granted by FERC to allow such exceptions to Applicable Requirements of CIP Standards.1

1.2. Authority This Appendix is a NERC Rule of Procedure and an Electric Reliability Organization Rule. As such, this Appendix has been approved by (i) the NERC Board of Trustees and (ii) FERC. Any future revisions to this Appendix must be adopted in accordance with Article XI, section 2 of the NERC Bylaws and Section 1400 of the NERC Rules of Procedure, including approval by the NERC Board of Trustees and by FERC, in order to become effective. 1.3. Scope This procedure for requesting and obtaining approval of TFEs is applicable only to those Requirements of CIP Standards CIP-002 through CIP-009 that (i) expressly provide either (A) that compliance with the terms of the Requirement is required where or as technically feasible, or (B) that technical limitations may preclude compliance with the terms of the Requirement, or (ii) FERC has directed should be subject to this procedure. As of the effective date of this Appendix, in the United States the Applicable Requirements are:

CIP-005-3: R2.4, R2.6, R3.1 and R3.2

CIP-006-3c: R1.1, including the Interpretation in Appendix 2

CIP-007-3: R2.3, R3, R4, R5.3, R 5.3.1, R 5.3.2, R 5.3.3, R6 and R6.3

Subsequent versions of these Requirements that are approved by FERC will continue to be Applicable Requirements, without the need to amend this Appendix to reflect the new version number of the CIP Standards, (i) if the subsequent versions continue to expressly provide either (A) that compliance with their terms is required where or as technically feasible or (B) that

1 Mandatory Reliability Standards for Critical Infrastructure Protection, 122 FERC ¶ 61,040 (2008) (Order No. 706), at PP 157-222.


Effective: January 31, 2012[DATE] -2-

technical limitations may preclude compliance with the terms of the Requirement2

; or (ii) so long as FERC does not direct that the subsequent versions are no longer Applicable Requirements. Other Requirements of CIP Standards may become Applicable Requirements as the result of revisions to the CIP Standards in accordance with the NERC Bylaws and Rules of Procedure including Appendix 3A, Standards Process Manual, or as a result of FERC directive. NERC shall maintain a current list of Applicable Requirements on its website.

1.4 Obligations of Canadian Entities and Cross-Border Regional Entities A Responsible Entity that is a Canadian Entity seeking a TFE shall work with the Regional Entity, NERC, and Applicable Governmental Authorities, to the extent permitted under Canadian federal or provincial laws, and without being obligated to authorize the disclosure of information prohibited by Canadian federal or provincial law from disclosure to FERC or other Applicable Governmental Authorities in the U.S., to comply with the requirements of this Appendix. A Canadian Entity shall not be required to subject itself to United States federal or state laws not otherwise applicable to the Canadian Entity in order to utilize this Appendix to obtain a TFE. Cross-Border Regional Entities shall implement this TFE Procedure in a manner consistent with their memoranda of understanding with Canadian Entities and Canadian Applicable Governmental Authorities concerning compliance monitoring and enforcement activities in particular provinces.

2.0. DEFINITIONS For purposes of this Appendix, capitalized terms shall have the definitions set forth in Appendix 2 to the Rules of Procedure. For ease of reference, the definitions of the following terms that are used in this Appendix are also set forth below: 2.1 Annual Report: The report to be filed by NERC with FERC and other Applicable Governmental Authorities in accordance with Section 13.0 of this Appendix. 2.2 Applicable Requirement: A Requirement of a CIP Standard that (i) expressly provides either (A) that compliance with the terms of the Requirement is required where or as technically feasible, or (B) that technical limitations may preclude compliance with the terms of the Requirement; or (ii) is subject to this Appendix by FERC directive. 2.3 Canadian Entity: A Responsible Entity that is organized under Canadian federal or provincial law. 2.4 Critical Infrastructure Protection Standard or CIP Standard: Any of NERC Reliability Standards CIP-002 through CIP-009.

2 Order No. 706 at P 157 and note 65 and P 178.



2.5 Classified National Security Information: Required Information that has been determined to be protected from unauthorized disclosure pursuant to Executive Order No. 12958, as amended, and/or the regulations of the NRC at 10 C.F.R. §95.35; or pursuant to any comparable provision of Canadian federal or provincial law. 2.6 CMEP: The NERC Uniform Compliance Monitoring and Enforcement Program (Appendix 4C to the NERC Rules of Procedure) or the Commission-approved program of a Regional Entity, as applicable. 2.7 Compliant Date: The date by which a Responsible Entity is required to be in compliance with an Applicable Requirement of a CIP Standard. 2.8 Confidential Information: (i) Confidential Business and Market Information; (ii) Critical Energy Infrastructure Information; (iii) personnel information that identifies or could be used to identify a specific individual, or reveals personnel, financial, medical, or other personal information; (iv) work papers, including any records produced for or created in the course of an evaluation or audit; (v) investigative files, including any records produced for or created in the course of an investigation; (vi) Cyber Security Incident Information; provided, that public information developed or acquired by an entity shall be excluded from this definition; or (vii) any other information that is designated as Confidential Information in Section 11.0 of this Appendix. 2.9 Covered Asset: A Cyber Asset or Critical Cyber Asset that is subject to an Applicable Requirement. 2.10 Delegate: A person to whom the Senior Manager of a Responsible Entity has delegated authority pursuant to Requirement R2.3 of CIP Standard CIP-003-1 (or any successor provision). 2.11 Effective Date: The date, as specified in a notice rejecting or disapproving a TFE Request or terminating an approved TFE, on which the rejection, disapproval or termination becomes effective. 2.12 Eligible Reviewer: A person who has the required security clearances or other qualifications, or who otherwise meets the applicable criteria, to have access to Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information, as applicable to the particular information to be reviewed. 2.13 Expiration Date: The date on which an approved TFE expires. 2.14 FERC: The United States Federal Energy Regulatory Commission. 2.15 FOIA: The U.S. Freedom of Information Act, 5 U.S.C. §552. 2.16 Hearing Procedures: Attachment 2 to the NERC or Regional Entity CMEP, as applicable.



2.17 Material Change: An update to an approved TFE that modifies key data in the TFE request. Examples of a Material Change could include, but are not limited to an increase in device count, change in compensating measures, change in statement of basis for the TFE, a change in the expiration date of the TFE, or a Responsible Entity achieving Strict Compliance with the Applicable Requirement. 2.18 Material Change Report: A report submitted by the Responsible Entity to the Regional Entity in the event there is a Material Change to the facts underlying an approved TFE. 2.179 NRC: The United States Nuclear Regulatory Commission. 2.18 20 NRC Safeguards Information: Required Information that is subject to restrictions on disclosure pursuant to 42 U.S.C. §2167 and the regulations of the NRC at 10 C.F.R. §73.21-73.23; or pursuant to comparable provisions of Canadian federal or provincial law. 2.19 Part A Required Information: Required Information that is to be provided in Part A of a Responsible Entity’s TFE Request. 2.20 Part B Required Information: Required Information that is to be provided in Part B of a Responsible Entity’s TFE Request. 2.21 Protected FOIA Information: Required Information, held by a governmental entity, that is subject to an exemption from disclosure under FOIA (5 U.S.C. §552(e)), under any similar state or local statutory provision, or under any comparable provision of Canadian federal or provincial law, which would be lost were the Required Information to be placed into the public domain. 2.22 Responsible Entity: An entity that is registered for a reliability function in the NERC Compliance Registry and is responsible for complying with an Applicable Requirement, as specified in the “Applicability” section of the CIP Standard. 2.23 Required Information: The information required to be provided in a TFE Request, as specified in Section 4.0 of this Appendix. 2.24 Senior Manager: The person assigned by the Responsible Entity, in accordance with CIP Standard CIP-003-1 Requirement R2 (or subsequent versions), to have overall responsibility for leading and managing the Responsible Entity’s implementation of, and adherence to, the CIP Standards. 2.25 Strict Compliance: Compliance with the terms of an Applicable Requirement without reliance on a Technical Feasibility Exception. 2.26 Technical Feasibility Exception or TFE: An exception from Strict Compliance with the terms of an Applicable Requirement on grounds of technical feasibility or technical limitations in accordance with one or more of the criteria in Section 3.0 of this Appendix.



2.27 TFE Request: A request submitted by a Responsible Entity in accordance with this Appendix for an exception from Strict Compliance with an Applicable Requirement. 3.0. BASIS FOR APPROVAL OF A TECHNICAL FEASIBILITY EXCEPTION 3.1. A Responsible Entity may request and obtain approval for a TFE on the grounds that Strict Compliance with an Applicable Requirement, evaluated in the context or environment of the Responsible Entity’s Covered Asset that is the subject of the TFE Request:

(i) is not technically possible or is precluded by technical limitations; or (ii) is operationally infeasible or could adversely affect reliability of the Bulk Electric System to an extent that outweighs the reliability benefits of Strict Compliance with the Applicable Requirement; or (iii) while technically possible and operationally feasible, cannot be achieved by the Responsible Entity’s Compliant Date for the Applicable Requirement, due to factors such as, for example, scarce technical resources, limitations on the availability of required equipment or components, or the need to construct, install or modify equipment during planned outages; or

(iv) would pose safety risks or issues that, in the determination of the Regional Entity,

outweigh the reliability benefits of Strict Compliance with the Applicable Requirement; or

(v) would conflict with, or cause the Responsible Entity to be non-compliant with, a

separate statutory or regulatory requirement applicable to the Responsible Entity, the Covered Asset or the related Facility that must be complied with and cannot be waived or exempted; or

(vi) would require the incurrence of costs that, in the determination of the Regional

Entity, far exceed the benefits to the reliability of the Bulk Electric System of Strict Compliance with the Applicable Requirement, such as for example by requiring the retirement of existing equipment that is not capable of Strict Compliance with the Applicable Requirement but is far from the end of its useful life and replacement with newer-generation equipment that is capable of Strict Compliance, where the incremental risk to the reliable operation of the Covered Asset and to the Reliable Operation of the related Facility and the Bulk Electric System of continuing to operate with the existing equipment is minimal in the determination of the Regional Entity.

3.2. A TFE does not relieve the Responsible Entity of its obligation to comply with the Applicable Requirement. Rather, a TFE authorizes an alternative (to Strict Compliance) means of compliance with the Applicable Requirement through the use of compensating measures and/or mitigating measures that achieve at least a comparable level of security for the Bulk Electric System as would Strict Compliance with the Applicable Requirement.



3.3. The burden to justify approval of a TFE Request in accordance with the provisions of this Appendix is on the Responsible Entity. It is the responsibility of the Regional Entity, subject to oversight by NERC as provided in this Appendix, to make all determinations as to whether a TFE Request has met the criteria for approval.3

NERC and the Regional Entities shall carry out the activities described in Section 11.0 of this Appendix to provide consistency in the review and approval or disapproval of TFE Requests across Regional Entities and across TFE Requests.

3.4. A TFE typically must be requested for, and will be approved only for, a limited duration, until a stated Expiration Date. The Responsible Entity will be expected to achieve Strict Compliance with the Applicable Requirement by the Expiration Date. Under limited, justified circumstances, aA TFE Request may be approved without a specified Expiration Date, however, in the event of a Material Change to the facts underlying an approved TFE, the Responsible Entity shall subject to periodic submit a Material Change Report providing review to verify continuing justification for the TFE or verifying Strict Compliance with the Applicable Requirement has been achieved. 4.0. FORM, CONTENTS AND SUBMISSION OF A TFE REQUEST 4.1. Separate Submissions for Eacha TFE Request A Responsible Entity may seek a TFE for class-based categories of devices. A list of permissible class-based categories of devices will be maintained on NERC’s web site. A separate TFE Request shall be submitted for each Applicable Requirement pertaining to each Covered Asset for which the Responsible Entity seeks a TFE. There is one exception to this requirement: where the In addition, a Responsible Entity may seeks use one submission to request a TFEsTFE from the same Applicable Requirement for multiple, similar Covered Assets (either at the same location or at different locations within the geographic boundaries of a Regional Entity) on the same basis, with the same compensating measures and/or mitigating measures, and with the same proposed Expiration Date, the TFE Requests for all the Covered Assets may be included in one submission. A TFE Request may not be submitted for Covered Assets located within the geographic boundaries of different Regional Entities. 4.2. Form and Format of TFE Request A TFE Request shall consist of two parts: 3 If a Regional Entity that is a Responsible Entity seeks a TFE in its role as a Responsible Entity, the Regional Entity shall submit its TFE Request to, as applicable, NERC or the Regional Entity that has assumed, by agreement approved by NERC and FERC, compliance monitoring and enforcement responsibilities with respect to the first Regional Entity’s registered functions, as applicable. In such case NERC or the second Regional Entity, as applicable, will perform the duties and responsibilities of the “Regional Entity” specified in this Appendix.



(i) Part A of the TFE Request is the notification to a Regional Entity that a Responsible Entity is requesting a TFE. Part A must be submitted in a secure electronic form using the template provided by the Regional Entity. Regional Entities will use the Part A Required Information for initial screening to accept or reject the TFE Request. (ii) Part B of the TFE Request contains the detailed material to support a TFE Request and includes the Documents, drawings, and other information necessary to provide the details and justification for the requested TFE. Part B must also include a detailed description of the compensating measures and/or mitigating measures the Responsible Entity will implement while the TFE is in effect. The Part B Required Information must be available at the Responsible Entity’s location for review by the Regional Entity and/or NERC beginning on the date the TFE Request is submitted.

(iii) A Regional Entity may also require the Responsible Entity to file all or a portion of the Part B Required Information with the Regional Entity, provided that (A) the information can be filed in a secure manner that does not compromise the confidentiality of any Confidential Information, Classified National Security Information, NRC Safeguards Information and/or Protected FOIA Information, and (B) the Responsible Entity shall not be required to file with a Regional Entity any Part B Required Information if, and to the extent that, such filing is prohibited by law.a spreadsheet or other template which would include the following Required Information:

a. Device ID b. Standard /Requirement c. Date of installation d. Compensating and Mitigating Measures e. Rational for the TFE (Statement of Basis) f. Whether the TFE is related to a self-certification or self-

report g. Whether the hasTFE been previously approved? h. TFE I.D., if known

Additional information may be requested by the Regional Entity as necessary or appropriate. At the discretion of the Regional Entity, information may be verified at a subsequent audit or spot-check or other form of monitoring.

4.3. [Deleted] Required Information to be Included in the TFE Request 4.3.1. Part A of a TFE Request shall contain the Part A Required Information specified in this Section 4.3.1 and shall be submitted to the Regional Entity using its template referred to in Section 4.2. Consistent with the summary nature of the Part A Required Information, the Regional Entity’s template may provide lists of responses to be selected by the Responsible Entity and/or limited space for narrative descriptions, for the Part A Required Information listed below. Failure to provide all Part A Required Information will result in rejection of the TFE Request as incomplete. The Part A Required Information shall consist of the following information: 1. Responsible Entity name.



2. Responsible Entity NERC ID. 3. TFE Request submittal date.

4. Whether the TFE Request is an original TFE Request or an amended TFE Request; and if it is an Amended TFE Request, the identification number of the original TFE Request.

5. Name, mailing address, phone number, facsimile number and E-mail address of

the Responsible Entity’s technical contact person for the TFE Request. 6. Applicable Requirement for which the TFE is being requested. 7. Number of Covered Assets for which the TFE is being requested. 8. Whether the Responsible Entity is filing a similar TFE Request(s) with one or

more other Regional Entities, and if yes, the name(s) of the other Regional Entity(ies).

9. The type(s) of equipment, process, or procedure at or associated with the Covered

Asset(s) and subject to or required by the Applicable Requirement, for which the TFE is being requested.

10. The basis for the TFE Request from the criteria specified in Section 3.1. 11. A brief statement describing and justifying why the Responsible Entity cannot

achieve Strict Compliance with the Applicable Requirement. 12. The estimated impact on Reliable Operation of the Bulk Electric System of the

Responsible Entity if the compensating measures and mitigating measures are not sufficient to achieve security for the Covered Assets, and cyber security is compromised.

13. A brief description of the compensating measures and/or mitigating measures that

are planned or have been implemented in lieu of achieving Strict Compliance with the Applicable Requirement.

14. A statement as to whether or not the compensating measures and/or mitigating

measures have been fully implemented at the time the TFE Request is submitted. 15. As applicable, (i) the actual implementation date(s) for the compensating

measures and/or mitigating measures, and/or (ii) the proposed date(s) for implementing the proposed compensating measures and/or mitigating measures.



16. Whether the Responsible Entity has a proposed plan and time schedule for terminating the TFE and achieving Strict Compliance with the Applicable Requirement; if yes, the proposed Expiration Date and a description of the plan for terminating the TFE; if no, an explanation as to why a TFE with no Expiration Date is being requested.

17. Whether the TFE Request is supported, in whole or in part, by any of the

following: Classified National Security Information; NRC Safeguards Information; or Protected FOIA Information.

18. A statement of the Responsible Entity’s understanding of the requirement to

submit timely periodic and other reports pertaining to the approved TFE. 19. A statement, signed and dated by the Responsible Entity’s Senior Manager or

Delegate, that the Senior Manager or Delegate has read the TFE Request and approved the proposed compensating measures and/or mitigating measures and the implementation plan, and that on behalf of the Responsible Entity that the Responsible Entity believes approval of the TFE Request is warranted pursuant to the criteria specified in Section 3.1 of this Appendix.

4.3.2 Part B of a TFE Request shall contain the Part B Required Information specified in

this Section 4.3.2. Failure to include all Part B Required Information may result in disapproval of the TFE Request. The information provided for items 3 through 8 below should be comprehensive, as opposed to the summary information provided on the Part A submission, and should include any supporting Documents.

1. A copy of Part A of the TFE Request. 2. Location(s) of the Covered Asset(s) for which the TFE is (are) requested.

3. A statement of the basis, consistent with Section 3.1 of this Appendix, on which

the Responsible Entity contends the TFE Request should be approved, with supporting documentation. Without limiting the content of this statement, it must include: (i) a description of the specific equipment, device(s), process(es) or procedure(s) at or associated with the Covered Asset(s) and subject to or required by the Applicable Requirement, for which the TFE is requested; and (ii) an explanation of why the Responsible Entity cannot achieve Strict Compliance with the Applicable Requirement.

4. A description of the compensating measures and/or mitigating measures the Responsible Entity proposes to implement and maintain as an alternate approach to achieving Strict Compliance with the Applicable Requirement, with supporting documentation. Without limiting the content of this description, it must include an explanation of how, and the extent to which, the proposed compensating measures and/or mitigating measures will reduce or prevent any adverse impacts on (i) the reliable operation of the Covered Asset(s) and (ii) the Reliable



Operation of the Element(s) and Facility(ies) of the Bulk Electric System for which the Responsible Entity is responsible, resulting from the failure to achieve Strict Compliance with the Applicable Requirement, including reducing or eliminating any vulnerabilities resulting from lack of Strict Compliance.

5. An assessment of the impacts on (i) reliable operation of the Covered Asset(s) and

(ii) Reliable Operation of the Elements and the Facility(ies), of the Bulk Electric System for which the Responsible Entity is responsible, if the proposed compensating measures and/or mitigating measures are insufficient or unsuccessful.

6. The Responsible Entity’s proposed time schedule for implementing the proposed

compensating measures and/or mitigating measures. The TFE Request may identify compensating measures and or mitigating measures that have already been implemented by the Responsible Entity.

7. The Responsible Entity’s proposed plan and time schedule for terminating the

TFE and achieving Strict Compliance with the Applicable Requirement, including the Responsible Entity’s proposed Expiration Date. The Responsible Entity should either (i) describe the specific steps it plans to take to achieve Strict Compliance and the planned schedule for each step, including the date by which the Responsible Entity intends to achieve Strict Compliance with the Applicable Requirement, and/or (ii) describe the specific research, design, analytical, testing or other activities the Responsible Entity intends to engage in to determine a means of achieving Strict Compliance with the Applicable Requirement, and the Responsible Entity’s proposed time schedule for these activities.

8. If the Responsible Entity contends it will not be possible for it to achieve Strict

Compliance with the Applicable Requirement and that the TFE being requested should have no Expiration Date, an explanation of why it will not be possible for the Responsible Entity to establish a date by which it can achieve Strict Compliance with the Applicable Requirement, why the TFE Request should be approved with no Expiration Date, and under what conditions, if any, the Responsible Entity will be able to achieve Strict Compliance with the Applicable Requirement at a future unknown and unspecified date.

9. The Responsible Entity’s commitment to file quarterly reports with the Regional

Entity on the Responsible Entity’s progress (i) in implementing the proposed compensating measures and/or mitigating measures, and (ii) towards achieving Strict Compliance with the Applicable Requirement.

If the proposed Expiration Date is more than one (1) year from the date the TFE Request is submitted, or if the Responsible Entity contends the TFE should have no Expiration Date, the Responsible Entity’s agreement to submit annual reports to the Regional Entity on the continued need for and justification for the TFE, for so long as the TFE remains in effect.



10. If the TFE Request is supported, in whole or in part, by Classified National Security Information, NRC Safeguards Information, and/or Protected FOIA Information, a statement identifying which of these categories each such item of information falls into and explaining why each such item of information is Classified National Security Information, NRC Safeguards Information, and/or Protected FOIA Information. If the Responsible Entity is prohibited by law from disclosing any Classified National Security Information, NRC Safeguards Information and/or Protected FOIA Information to any person who is not an Eligible Reviewer (such as, for example, the restriction on access to Classified National Security Information specified in Section 4.1 of Executive Order No. 12958, as amended), the TFE Request shall identify the Classified National Security Information, NRC Safeguards Information and/or Protected FOIA Information that is subject to such restrictions on disclosure and shall identify the criteria which a person must meet in order to be an Eligible Reviewer of the Classified National Security Information, NRC Safeguards Information and/or Protected FOIA Information.

12. A statement, signed and dated by the Senior Manager or Delegate, that the Senior

Manager or Delegate has read the TFE Request and approved the compensating measures and/or mitigating measures and the implementation plan, and on behalf of the Responsible Entity that the Responsible Entity believes approval of the TFE Request is warranted pursuant to the criteria in Section 3.1 of this Appendix.

4.3.3. All scheduled implementation dates and other activity dates, and the Expiration Date, in the TFE Request shall be stated as specific calendar dates.

4.4 Access to Confidential Information, Classified National Security Information, NRC Safeguards Information, and Protected FOIA Information Included in Required Information

4.4.1. Upon reasonable advance notice from a Regional Entity or NERC, and subject to Section 4.4.2, the Responsible Entity must provide the Regional Entity or NERC (i) with access to Confidential Information, Classified National Security Information, NRC Safeguards Information, and Protected FOIA Information included in the Part B Required Informationthe TFE Request, and (ii) with access to the Covered Asset(s) and the related Facility(ies) for purposes of making a physical review and inspection. 4.4.2. If the Responsible Entity is prohibited by law from disclosing any Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information to any person who is not an Eligible Reviewer (such as, for example, the restriction on access to Classified National Security Information specified in Section 4.1 of Executive Order No. 12958, as amended), then such Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information



shall only be reviewed by a representative or representatives of the Regional Entity or NERC (which may include contractors) who are Eligible Reviewers.

4.4.3. The Regional Entity or NERC, as applicable, will work cooperatively with the Responsible Entity to access Protected FOIA Information in a way that does not waive or extinguish the exemption of the Protected FOIA Information from disclosure.

4.5 Submission of TFE Request in Advance of Compliant Date

The Responsible Entity should submit a TFE Request at least sixty (60) calendar days prior to the Responsible Entity’s Compliant Date for the Applicable Requirement that is the subject of the TFE Request, to avoid the risk that the initial screeningreview will not be completed by the Compliant Date and the Responsible Entity will become subject to issuance of a Notice of Alleged Violation for noncompliance with the Applicable Requirement. However, if a Responsible Entity whose Compliant Date for an Applicable Requirement was on or before December 31, 2009, submits a TFE Request for the Applicable Requirement by January 31, 2010 (either pursuant to this Appendix or pursuant to NERC Compliance Process Bulletin #2009-007 and Attachments 1 and 2 to that Bulletin), the Compliant Date will be deemed to be the date of submission of the TFE Request for purposes of Section 5.3 of this Appendix.

5.0 REVIEW, ACCEPTANCE/REJECTION, AND APPROVAL/DISAPPROVAL OF

TFE REQUESTS

5.1. Initial Screening of TFE Requests for Acceptance or Rejection 5.1.1. Upon receipt of Part A of a a TFE Request, the Regional Entity (i) will assign a unique identifier to the TFE Request, and (ii) will review the TFE Request to determine that the TFE Request is for an Applicable Requirement and that all Part A Required Information has been provided. 5.1.2. The unique identifier assigned to the TFE Request will be in the form of XXXX-YYY-TFEZZZZZ, where “XXXX” is the year in which the TFE Request is received by the Regional Entity (e.g., “2009”); “YYY” is the acronym for the Regional Entity within whose Region the Covered Asset is located4

4 The acronyms to be used are: FRCC (Florida Reliability Coordinating Council); MRO (Midwest Reliability Organization); NPCC (Northeast Power Coordinating Council); RFC (ReliabilityFirst Corporation); SERC (SERC Reliability Corporation); SPP (Southwest Power Pool Regional Entity); TRE (Texas Regional Entity/Texas Reliability Entity); and WECC (Western Electricity Coordinating Council).

; and “ZZZZZ” is the sequential number of the TFE Requests received by the Regional Entity in that year. If the TFE Request is amended or resubmitted, “-AZ” will be added to the end of the identifier, where “Z” is the number of the amendment to the TFE Request.



5.1.3. (a) The Regional Entity will typically complete its initial screening within sixty

(60) calendar days after receiving the TFE Request.

(b) If the Regional Entity determines at any time that for a specified period of time, the Regional Entity will be unable to complete initial screenings of TFE Requests within sixty (60) calendar days after receipt and substantive reviews of TFE Requests within one year after receipt, the Regional Entity, based on consultation with NERC, shall establish an alternative time period objective and work plan for completing initial screenings and substantive reviews of TFE Requests during the specified period of time. The alternative time period objective and work plan shall be publicized by issuance of a notice to all Registered Entities within the geographic boundaries of the Regional Entity and by posting on the Regional Entity’s website.

(c) If the Regional Entity is unable to complete its initial screening within sixty (60) calendar days after receiving the TFE Request, the Responsible Entity will not be subject to imposition of any findings of violations, or imposition of Penalties or sanctions for violations, for failure to be in Strict Compliance with the Applicable Requirement that is the subject of the TFE Request, beginning on the sixty-first (61st) calendar day after the Regional Entity received the TFE Request and continuing thereafter in accordance with Section 5.3.

5.1.4. If, based on its initial screening, the Regional Entity determines the TFE Request is for an Applicable Requirement and contains all Part A Required Information, and that the Part A Required Information provided by the Responsible Entity indicates the TFE Request satisfies the criteria for approval of a TFE in Section 3.1 of this Appendix, the Regional Entity shall send a notice to the Responsible Entity, with a copy to NERC, accepting the TFE Request as complete. 5.1.5. If the Regional Entity determines, based on its review of the Part A Required Information provided by the Responsible Entity, that the TFE Request (i) is not for an Applicable Requirement, or (ii) does not contain all Part A Required Information, or (iii) does not satisfy the criteria for approval of a TFE in Section 3.1 of this Appendix, the Regional Entity shall send a notice to the Responsible Entity, with a copy to NERC, rejecting the TFE Request. The notice shall state an Effective Date which shall be no less than thirty-one (31) calendar days and no more than sixty-one (61) calendar days after the date of issuance of the notice, unless the Regional Entity determines there are exceptional circumstances that justify a later Effective Date. If the Regional Entity determines the Effective Date should be more than sixty-one (61) calendar days after the date of issuance of the notice due to exceptional circumstances, the Regional Entity shall include a detailed statement of the exceptional circumstances in the notice. 5.1.6. If the Regional Entity rejects the TFE Request because not all Part A Required Information was provided, the Regional Entity’s notice shall identify the Part A Required Information that was not provided in the TFE Request. The Responsible Entity may resubmit the TFE Request with all Part A Required Information included. If the Responsible Entity resubmits



the TFE Request with all Part A Required Information included prior to the Effective Date, the Responsible Entity will not be subject to imposition of any findings of violations, or imposition of Penalties or sanctions for violations, for failure to be in Strict Compliance with the Applicable Requirement that is the subject of the TFE Request, during the period the Regional Entity is conducting initial screening of the resubmitted TFE Request. The Responsible Entity may resubmit a TFE Request pursuant to this Section 5.1.6 only one time. 5.1.7. The Regional Entity may must either accept the TFE Request in its entirety or reject the TFE Request in its entirety, even if the TFE Request is for two or more Covered Assets subject to the same Applicable Requirement. 5.2 Substantive Review of TFE Request for Approval or Disapproval 5.2.1 The Regional Entity shall conduct a substantive review of an accepted a TFE Request to determine if it should be approved in accordance with Section 3.1 of this Appendix, or disapproved. The Regional Entity will conduct the substantive review in accordance with established compliance monitoring processes under the CMEP, such as a Compliance Audit or Spot Check.. The compliance monitoring activity may be conducted solely for the purpose of substantive review of the TFE Request, or may include review of the Responsible Entity’s compliance with other Reliability Standards. As part of its substantive review, the Regional Entity may request access to and review the Part B Requiredthe Required Information, including any Confidential Information, Classified National Security Information, NRC Safeguards Information, and Protected FOIA Information that is necessary to support the TFE Request; may conduct one or more physical inspections of the Covered Asset(s) and the related Facility(ies); may request additional information from the Responsible Entity; and may engage in discussions with the Responsible Entity concerning possible revisions to the TFE Request. 5.2.2. The Regional Entity shall complete its substantive review of the TFE Request and make its determination of whether the TFE Request is approved or disapproved, and issue a notice (in accordance with Sections 5.2.4 or 5.2.5) stating the TFE Request is approved or disapproved, within one (1) year after receipt of the TFE Request or within an alternative time period objective as specified in a work plan established under Section 5.1.3(b). In addition, the Regional Entity may extend the one-year time period for individual TFE Requests by issuing a notice to the Responsible Entity, with a copy to NERC, stating the revised date by which the Regional Entity will issue its notice approving or disapproving the TFE Request. 5.2.3. The Regional Entity may must either approve or disapprove t the TFE Request in whole or in its entirety or disapprove the TFE Request in its entiretypart, even if the TFE Request is for two or more Covered Assets subject to the same Applicable Requirement or if it covers class-based categories of devices. 5.2.4. If the Regional Entity approves the TFE Request, the Regional Entity shall issue a notice to the Responsible Entity, with a copy to NERC, stating that the TFE Request is approved.



5.2.5. If the Regional Entity disapproves the TFE Request, the Regional Entity shall issue a notice to the Responsible Entity, with a copy to NERC, stating that the TFE Request is disapproved and stating the reasons for the disapproval. In its notice disapproving a TFE Request, the Regional Entity may also, but is not required to, state any revisions to the TFE Request the Regional Entity has identified, based on its review of the TFE Request, that, if made by the Responsible Entity, would result in approval of the TFE Request. Such revisions may include, but are not limited to, changes to the Responsible Entity’s proposed (i) compensating measures and/or mitigating measures, (ii) implementation schedules, or (iii) Expiration Date. If the Responsible Entity submits an amended TFE Request to the Regional Entity incorporating, to the Regional Entity’s satisfaction, the revisions to the TFE Request set forth in the notice of disapproval, then the Regional Entity shall issue a notice, in accordance with Section 5.2.4, approving the revised TFE Request. 5.2.6. A notice disapproving a TFE Request shall state an Effective Date, which shall be no less than sixty-one (61) calendar days and no more than ninety-one (91) calendar days after the date of issuance of the notice, unless the Regional Entity determines there are exceptional circumstances that justify a later Effective Date. If the Regional Entity determines the Effective Date should be more than ninety-one (91) calendar days after the date of issuance of the notice due to exceptional circumstances, the Regional Entity shall include a detailed statement of the exceptional circumstances in the notice. Following the Effective Date, the Responsible Entity is subject to issuance of a Notice of Alleged Violation by the Regional Entity with respect to the Applicable Requirement that was the subject of the disapproved TFE Request, unless the Responsible Entity (i) has submitted an amended TFE Request in accordance with Section 5.2.5, or (ii) has achieved Strict Compliance with the Applicable Requirement. Provided, that if the Effective Date occurs prior to the Responsible Entity’s Compliant Date for the Applicable Requirement, then the Responsible Entity is not subject to issuance of a Notice of Alleged Violation until the Compliant Date. A Notice of Alleged Violation issued with respect to the Applicable Requirement shall be processed in accordance with Sections 5.0, 6.0 and 7.0 of the CMEP. 5.2.7 Within thirty (30) calendar days after issuing a notice approving or disapproving a TFE Request, the Regional Entity shall submit a report to NERC setting forth the basis on which the Regional Entity approved or disapproved the TFE Request. If the Regional Entity has disapproved the TFE Request and determined there were exceptional circumstances justifying an Effective Date more than ninety-one (91) days after the date of issuance of the notice, the Regional Entity’s report to NERC shall include a description of such exceptional circumstances. 5.2.8 A Responsible Entity may submit to NERC information that the Responsible Entity believes demonstrates that the approval, or disapproval or rejection by a Regional Entity of a TFE Request submitted by the Responsible Entity constitutes an inconsistent application of the criteria specified in Section 3.1 as compared to other determinations of TFE Requests made by the same Regional Entity or another Regional Entity for the same type of Covered Assets, and with such submission may suggest that NERC request the Regional Entity to reconsider its approval, or disapproval or rejection of the TFE Request. A Responsible Entity’s submission to NERC under this Section 5.2.8 shall be in writing and shall set forth (i) the TFE Request for which the Responsible Entity received a determination that the Responsible Entity believes



represents an inconsistent application of the criteria specified in Section 3.1 (using the identifier assigned to the TFE Request pursuant to Section 5.1.2), (ii) a copy of the Regional Entity’s notice of approval, or disapproval or rejection of the TFE Request, and (iii) a description of the inconsistency in determinations that the Responsible Entity believes has occurred, including specific reference(s) to any other determinations of TFE Requests for the same type of Covered Assets that the Responsible Entity believes constitutes inconsistent application of the criteria specified in Section 3.1. The Responsible Entity’s submission shall provide a clear and compelling demonstration that inconsistent applications of the criteria specified in Section 3.1 have occurred in the determinations of two or more TFE Requests for the same type of Covered Assets made by the same Regional Entity or two or more Regional Entities. NERC will provide a copy of the Responsible Entity’s submission to the Regional Entity that approved, or disapproved or rejected the TFE Request that is the subject of the submission. NERC will review the Responsible Entity’s submission and the reports submitted by the Regional Entity or Regional Entities pursuant to Section 5.2.7 with respect to the TFE Requests that are the subject of the Responsible Entity’s submission, and may decide, in accordance with Section 5.2.9, to request the Regional Entity to reconsider its determination. NERC will send a written notice to the Responsible Entity stating that NERC has determined to request reconsideration by the Regional Entity or has determined not to request reconsideration by the Regional Entity, as applicable. 5.2.9 NERC may request the Regional Entity to reconsider the approval, or disapproval or rejection of a TFE Request, solely on the grounds that the approval, or disapproval or rejection would result in inconsistent application of the criteria specified in Section 3.1 as compared to determinations made on TFE Requests for the same type of Covered Assets by the same Regional Entity or a different Regional Entity. Requests for reconsideration on any other grounds are not allowed. A request for reconsideration shall be submitted in writing to the Regional Entity and shall set forth (i) the TFE Request that is the subject of the request for reconsideration (using the identifier assigned to the TFE Request pursuant to Section 5.1.2), (ii) a copy of the Regional Entity’s notice of approval, or disapproval or rejection of the TFE Request, and (iii) a description of the inconsistency in determinations on which NERC relies as the basis for the request for reconsideration, including specific reference(s) to other determinations of TFE Requests for the same type of Covered Asset that NERC believes constitutes inconsistent application of the criteria specified in Section 3.1. The Regional Entity shall consider the request for reconsideration and shall issue a notice to NERC and the affected Responsible Entity(ies) approving, disapproving or rejecting the TFE Request in accordance with Section 5.1.4, Section 5.1.5, Section 5.2.4, Section 5.2.5, Section 5.2.6 and/or Section 9.2, as applicable, within one hundred twenty (120) days following receipt of the request for reconsideration. A determination on a request for reconsideration approving, or disapproving or rejecting a TFE Request shall be effective prospectively only, from its Effective Date, provided, that if a Regional Entity receives a request for reconsideration of the rejection or disapproval of a TFE Request prior to the Effective Date of the notice of rejection or disapproval, the Regional Entity shall issue a notice to the affected Responsible Entity pursuant to Section 5.1.5 or Section 5.2.6, as applicable, suspending the Effective Date pending determination of the request for reconsideration.

5.3 No Findings of Violations or Imposition of Penalties for Violations of an

Applicable Requirement for the Period a TFE Request is Being Reviewed



The Responsible Entity shall not be subject to imposition of any findings of violations, or imposition of Penalties or sanctions for violations, for failure to be in Strict Compliance with an Applicable Requirement that is the subject of a TFE Request, for the period from:

(i) the earlier of (A) the date of the Regional Entity’s notice that the TFE Request is accepted as complete and (B) the date that is sixty (60) calendar days after submission of the TFE Request,

to: (ii) (A) the Effective Date of the Regional Entity’s notice that the TFE Request is

rejected, or (B) the date of the Regional Entity’s notice that the TFE Request is approved, or (CB) the Effective Date of the Regional Entity’s notice that the TFE Request is disapproved, whichever is applicable.

Provided, that:

(1) while a TFE Request is undergoing initial screeningreview, the Regional Entity shall not issue a Notice of Alleged Violation to the Responsible Entity for being noncompliant with the Applicable Requirement that is the subject of the TFE Request during the period on and after the TFE Request was submitted;

(2) if the TFE Request is acceptedapproved, the Responsible Entity shall not be

subject to imposition of any findings of violations, or imposition of Penalties or sanctions for violations, for failure to be in Strict Compliance with an Applicable Requirement that is the subject of the TFE Request, during the period from submission of the TFE Request to the date of the Regional Entity’s notice that the TFE Request is acceptedapproved; and

(3) if the TFE Request is disapproved, and is found by the Regional Entity, NERC or

FERC to have been fraudulent or submitted not in good faith, the provisions of this Section 5.3 shall not apply, the Responsible Entity shall be subject to imposition of findings of violations and imposition of Penalties or sanctions for violations, for failure be in Strict Compliance with the Applicable Requirement that was the subject of the TFE Request, for the entire period subsequent to the date the TFE Request was submitted, and the Responsible Entity’s fraudulent or not-in-good-faith submission of the TFE Request shall be an aggravating factor in determining the amounts of Penalties or sanctions to be imposed on the Responsible Entity for such violations.

6.0 IMPLEMENTATION AND REPORTING BY THE RESPONSIBLE ENTITY

PURSUANT TO AN APPROVED TFE



6.1. The Responsible Entity will be required to implement compensating measures and/or mitigating measures as described, and in accordance with the time schedule(s) set forth, in the approved TFE. 6.2. In the event Unless the TFE has been approved with noan Expiration Date, the Responsible Entity will be required to implement steps, or conduct research and analysis, towards achieving Strict Compliance with the Applicable Requirements and eliminating the TFE, as described, and in accordance with the time schedule set forth, in the approved TFE. 6.3. [Deleted]The Responsible Entity shall submit quarterly reports to the Regional Entity on (i) the Responsible Entity’s progress in implementing the compensating measures and/or mitigating measures the Responsible Entity is adopting pursuant to the approved TFE, and (ii) the Responsible Entity’s progress in implementing steps and/or conducting research and/or analysis to achieve Strict Compliance with the Applicable Requirement. 6.4. [Deleted]All quarterly reports shall be submitted to the Regional Entity by no later than the last business day of the month immediately following the end of the calendar quarter for which the report is being submitted. 6.5. If there is a Material Change in the facts underlying approval of the TFE Expiration Date of the TFE is more than one (1) year after the TFE Request was submitted, or if the approved TFE has no Expiration Date, the Responsible Entity shall submit annual reportsa report to the Regional Entity supporting the continuing need and justification for the approved TFE or verifying that the Responsible Entity has achieved Strict Compliance with the Applicable Requirement. The first annual report shall be due on the last business day of the month immediately following the end of the fourth calendar quarter after acceptance of the TFE Request. The annual report shall contain information as specified in items 1 through 10 and 13 of Section 4.3.2, but revised as appropriate based on current information as of the date of the report. The annual report shall not propose revisions to implementation, research and reporting dates that were specified in the approved TFE, but rather shall report on the Responsible Entity’s progress and accomplishments in carrying out the implementation and research activities. Any revisions to implementation, research and reporting dates, or to other requirements, that were specified in the approved TFE shall be requested by an amendment filing in accordance with Section 7.2 of this Appendix The Material Change Report shall be submitted as an amendment to the initial TFE request. 6.6. Each Material Change report submitted pursuant to Section 6.3 or Section 6.5Report shall include a statement, signed and dated by the Senior Manager or Delegate, that the Senior Manager or Delegate has read, and approved the submission of, the report. 6.7. The Regional Entity shall issue an acknowledgement notice to the Responsible Entity and to NERC that a report has been received, but no other issuances shall be required from the Regional Entity in response to submission of such a report.



6.8. If a Responsible Entity fails to implement or maintain a compensating measure or mitigating measure or fails to conduct research or analysis towards achieving Strict Compliance, in accordance with the approved TFE; or fails to submit one or more reports by the required submission date, the Responsible Entity (i) is required to file a Self-Report in accordance with Section 3.5 of the CMEP, and (ii) will be subject to issuance of a Notice of Alleged Violation for noncompliance with the Applicable Requirement that is the subject of the approved TFE. Any such Notice of Alleged Violation shall be processed in accordance with Sections 5.0, 6.0 and 7.0 of the CMEP. 6.9. At least thirty (30) calendar days prior to the Expiration Date, the Responsible Entity shall submit a report to the Regional Entity, signed and dated by the Senior Manager or Delegate, demonstrating that the Responsible Entity has achieved, or will be able to achieve by the Expiration Date, Strict Compliance with the Applicable Requirement.

7.0 AMENDMENT OF A TFE REQUEST OR APPROVED TFE 7.1. Amendment of a Pending TFE Request A Responsible Entity may at any time amend a pending TFE Request that is under review by a Regional Entity, for the purpose of providing additional or revised Required Information. The Responsible Entity shall submit an amended Part A and shall include in the Part B Required Information a written explanation of what Required Information is being added or revised and the purpose of the amendment.during the 60-day review Submissionperiod. Submission of an amendment to a pending TFE Request may, in the Regional Entity’s discretion, extend the time period for the Regional Entity’s initial screening or substantive review, as applicable, of the TFE Request. but does not require the restart of the approval process. 7.2. Amendment of an Approved TFE 7.2.1. A Responsible Entity may submit an amendment to an approved TFE for the purpose of requesting revision to any of the requirements specified in the approved TFE, such as, for example, revisions to the specific compensating measures and/or mitigating measures to be implemented, revisions to the schedule for implementing the compensating measures and/or mitigating measures, or a change in the Expiration Date. The Responsible Entity shall submit all the Part A Required Information, as amended, as specified in Section 4.3.1, and make available the Part B Required Information, as amended, as specified in Section 4.3.2. The Responsible Entity shall also include in the Part B Required InformationThe Responsible Entity shall include a written explanation of the amendment, the reason for and purpose of the amendment, and the reason the requirements in the approved TFE should be revised. 7.2.2. The Regional Entity shall review the amended Part A Required Information to determine if it is complete, and shall issue a notice to the Responsible Entity, with a copy to NERC, stating if the amendment is accepted as complete or rejected as incomplete. If the Regional Entity issues a notice that the amendment is accepted as complete, the Regional Entity shall conduct a substantive review of the amendment, including such review of the amended Part B Required Information as the Regional Entity deems necessary,



7.2.2. The Regional Entity shall review the amendment to determine if the amended TFE Request should be approved or disapproved, and shall issue a notice of approval or disapproval, in accordance with Section 5.2. If the Regional Entity determines the amendment should be approved, the TFE as amended replaces the previously approved TFE. 7.2.3. An approved TFE that is the subject of an amendment filing remains in effect unless and until the amendment is approved by the Regional Entity.

8.0 COMPLIANCE AUDIT REQUIREMENTS RELATING TO APPROVED TFE

8.1. Following approval of a Responsible Entity’s TFE Request, subsequent Compliance Audits of the Responsible Entity conducted prior to the Expiration Date shallmay include audit of (i) the Responsible Entity’s implementation and maintenance of the compensating measures and/or mitigating measures specified in the approved TFE, in accordance with the time schedule set forth in the approved TFE, and (ii) the Responsible Entity’s implementation of steps and conduct of research and analyses towards achieving Strict Compliance with the Applicable Requirement, in accordance with the time schedule set forth in the approved TFE. These topics shall be included in such Compliance Audits regardless of whether a Compliance Audit was otherwise scheduled to include the CIP Standard that includes the Applicable Requirement.

8.2 The first Compliance Audit of the Responsible Entity subsequent to the Expiration Date shall include audit of the Responsible Entity’s Strict Compliance with the Applicable Requirement that was the subject of the approved TFE. This topic shall be included in such Compliance Audit regardless of whether it was otherwise scheduled to include the CIP Standard that includes the Applicable Requirement.

9.0 TERMINATION OF AN APPROVED TFE 9.1. An approved TFE shall remain in effect unless it terminates on its Expiration Date, unless itDate, it is terminated at an earlier date pursuant to this Section 9.0, the Responsible Entity achieves Strict Compliance with the Applicable Requirement or there is a material misrepresentation by the Responsible Entity as to the facts relied upon by the Regional Entity in approving the TFE. 9.2. The Responsible Entity may terminate an approved TFE by submitting a notice to the Regional Entity stating that the Responsible Entity is terminating the TFE and the Effective Date of the termination. 9.3. A Regional Entity or NERC may terminate an approved TFE based on the results of a Spot Check initiated and conducted pursuant to the CMEP to determine whether the approved TFE should be terminated prior to its Effective Date or should be revised to impose additional or different requirements or to advance the Expiration Date to an earlier date. Following issuance to the Responsible Entity of a draft Spot Check report concluding that the approved TFE should be terminated or revised (including by advancement of the Expiration Date), and opportunity for the Responsible Entity to submit comments on the draft Spot Check report, the Regional Entity



or NERC, if it has determined that the approved TFE should be terminated or revised, shall issue a notice of termination to the Responsible Entity (with a copy to NERC if the notice is issued by the Regional Entity) stating the Effective Date of termination of the approved TFE. The Effective Date shall be no less than sixty-one (61) calendar days and no more than ninety-one (91) calendar days after the date of issuance of the notice of termination, unless the Regional Entity determines there are exceptional circumstances that justify a later Effective Date. If the Regional Entity determines the Effective Date should be more than ninety-one (91) calendar days after the issuance of the notice of termination due to exceptional circumstances, the Regional Entity shall include a detailed statement of the exceptional circumstances in the notice of termination. 9.4. The Responsible Entity shall not be subject to imposition of any findings of violations, or imposition of Penalties or sanctions for violations, for failure to be in Strict Compliance with an Applicable Requirement that is the subject of a TFE that has been terminated, until the Effective Date of the notice of termination. 10.0 [Deleted] HEARINGS AND APPEALS PROCESS FOR RESPONSIBLE ENTITY A Responsible Entity whose TFE Request has been rejected or disapproved, or whose approved TFE has been terminated, and thereafter receives a Notice of Alleged Violation for the Applicable Requirement that was the subject of the TFE Request or the approved TFE, is entitled to a hearing before the Regional Entity Hearing Body (or before the NERC Compliance and Certification Committee if NERC is the Compliance Enforcement Authority with respect to the Responsible Entity’s compliance with the Applicable Requirement), in accordance with the Hearing Procedures, if the Responsible Entity contests the Notice of Alleged Violation, the proposed Penalty or sanction, or Mitigation Plan components. The Responsible Entity may raise issues relating to the rejection or disapproval of its TFE Request or the termination of the approved TFE in the hearing concerning the Notice of Alleged Violation, proposed Penalty or sanction, or Mitigation Plan components. 11.0 CONSISTENCY IN APPROVAL AND DISAPPROVAL OF TFE REQUESTS 11.1. NERC and the Regional Entities will engage in the activities specified in this Section 11.0 for the purpose of assuring consistency in the review, approval and disapproval of TFE Requests (i) among the Regional Entities, (ii) among different types of Covered Assets that are subject to the same Applicable Requirement, (iii) with respect to the application of the criteria specified in Section 3.1 for approval of TFE Requests, including the comparison of safety risks and costs of Strict Compliance to reliability benefits of Strict Compliance, and (iv) with respect to the types of mitigating measures and compensating measures that are determined to be appropriate to support approval of TFE Requests. In appropriate cases, NERC will submit a request for reconsideration to a Regional Entity in accordance with Section 5.2.9. 11.2. The activities in which NERC and the Regional Entities will engage for the purposes stated in Section 11.1 will include, but not be limited to, the following activities:



1. [Deleted] NERC will review the reports of approved and disapproved TFE Requests submitted by the Regional Entities pursuant to Section 5.2.7 as the reports are received, and based on its review of such reports, NERC will issue to the Regional Entities, as Confidential Information, such guidance as NERC deems appropriate to achieve greater consistency in approval and disapproval of TFE Requests in the respects listed in Section 11.1.

2. NERC will maintain, as Confidential Information, based on reports submitted by

Regional Entities, a catalogue of the types of Covered Assets for which TFE Requests from the various Applicable Requirements have been approved and disapproved. The catalogue will be accessible to the Regional Entities for their use in connection with their substantive reviews of TFE Requests.

3. NERC and the Regional Entities will form a committee comprised of NERC and

Regional Entity representatives involved in the review of TFE Requests and other Critical Infrastructure program activities, which shall be charged to review approved and disapproved TFE Requests for consistency and to issue such guidance to the Regional Entities, as Confidential Information, as the committee deems appropriate to achieve greater consistency in approval and disapproval of TFE Requests in the respects listed in Section 11.1. The committee shall include persons with appropriate subject matter expertise for the responsibilities and activities of the committee.

4. NERC will submit to the FERC and to other Applicable Governmental Entities an

annual informational report containing the following information concerning the manner in which Regional Entities have made determinations to approve or disapprove TFE Requests based on the criteria of Section 3.1:

(i) whether any issues were identified during the period covered by the

informational report with respect to the consistency of the determinations made based on the criteria in Section 3.1, either within a Regional Entity or among Regional Entities;

(ii) a description of any such identified consistency issues; (iii) how each consistency issue was resolved; (iv) the numbers of TFE Requests for which reconsideration was requested

pursuant to Section 5.2.9 based on purported inconsistencies in determinations applying the criteria in Section 3.1 and the numbers of such requests which resulted in TFE Requests being approved, or disapproved and rejected; and

(v) whether NERC has developed or is in a position to develop a uniform

framework for Regional Entities to use to appraise the reliability benefits of Strict Compliance when making determinations based on the criteria in Section 3.1(iv) and (vi).



The first such informational report shall cover the period through June 30, 2011,

and shall be filed with FERC and other Applicable Governmental Entities no later than September 28, 2011. Subsequent annual informational reports shall cover the period from July 1 through June 30 and shall be filed within 90 days following the end of the period covered by the report.

If NERC determines it is necessary to include any Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information in an informational report in order to satisfy the information requirements specified above, such Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information shall be contained in a separate non-public, confidential appendix to the informational report. Prior to submitting to FERC or another Applicable Governmental Authority a non-public, confidential appendix that provides specific Confidential Information, Classified National Security Information, NRC Safeguards Information, or Protected FOIA Information of a particular Responsible Entity and identifies the Responsible Entity or one of its Facilities by name, NERC shall provide at least twenty-one (21) days advance notice to the Responsible Entity. The non-public, confidential appendix shall be submitted to FERC and other Applicable Governmental Authorities in accordance with their procedures for receiving confidential, proprietary and other protected information.

12.0 CONFIDENTIALITY OF TFE REQUESTS AND RELATED INFORMATION Except as expressly stated in this Section 12.0, the submission, review, acceptance/rejection, and approval/disapproval of TFE Requests, and the implementation and termination of approved TFEs, shall be maintained as confidential. The following Documents are Confidential Information and shall be treated as such in accordance with Section 1500 of the NERC Rules of Procedure:

(i) All TFE Requests and proposed amendments, including without limiting the foregoing the Required Part A Information and Required Part B Information submitted, filed or made available by the Responsible Entity;

(ii) All notices issued by a Regional Entity or NERC pursuant to this Appendix; (iii) All requests for Documents or information made by a Regional Entity or NERC

pursuant to this Appendix; (iv) All submissions of Documents and information by a Responsible Entity to a

Regional Entity or NERC pursuant to this Appendix; (v) All post-approval reports submitted by a Responsible Entity pursuant to this

Appendix;



(vi) All correspondence, notes, drawings, drafts, work papers, electronic

communications, reports and other Documents generated by a Regional Entity or NERC in connection with a TFE Request, including (without limiting the scope of this provision) in connection with reviewing a TFE Request and supporting Documents and information submitted, filed or made available by the Responsible Entity, conducting a physical inspection of the Covered Asset(s) or the related Facility(ies), reviewing and analyzing post-approval reports submitted by a Responsible Entity, or conducting compliance monitoring processes pursuant to the CMEP with respect to a TFE Request or approved TFE.

(vii) All guidance issued to Regional Entities pursuant to Section 11.2 by NERC or by

the committee described in Section 11.2(3), and all minutes of meetings of the committee and discussions between or among its members.

(viii) All submissions by Responsible Entities to NERC pursuant to Section 5.2.8.

(ix) All requests for reconsideration pursuant to Section 5.2.9.

(x) Any confidential appendix to an informational report prepared and submitted

pursuant to Section 11.2(4) or to an Annual Report prepared and submitted pursuant to Section 13.0.

13.0 ANNUAL REPORT TO FERC AND OTHER APPLICABLE GOVERNMENTAL AUTHORITIES 13.1. Contents of Annual Report NERC shall submit an Annual Report to FERC that provides a Wide-Area analysis or analyses, which NERC shall prepare in consultation with the Regional Entities, regarding the use of TFEs and the impact on the reliability of the Bulk Electric System, as required by Paragraphs 220 and 221 of Order No. 706, which state: . . . [W]e direct the ERO to submit an annual report to the Commission that

provides a wide-area analysis regarding use of the technical feasibility exception and the effect on Bulk-Power System reliability. The annual report must address, at a minimum, the frequency of the use of such provisions, the circumstances or justifications that prompt their use, the interim mitigation measures used to address vulnerabilities, and efforts to eliminate future reliance on the exception. . . [T]he report should contain aggregated data with sufficient detail for the Commission to understand the frequency with which specific provisions are being invoked as well as high level data regarding mitigation and remediation plans over time and by region . . . .

Copies of the Annual Report shall be filed with other Applicable Governmental Authorities. The Annual Report shall contain, at a minimum, the following information:



(i) The frequency of use of the TFE Request process, disaggregated by Regional

Entity and in the aggregate for the United States and for the jurisdictions of other Applicable Governmental Authorities, including (A) the numbers of TFE Requests that have been submitted, accepted/rejected, and approved/disapproved during the preceding year and cumulatively since the effective date of this Appendix, (B) the numbers of unique Covered Assets for which TFEs have been approved, (C) the numbers of approved TFEs that are still in effect as of on or about the date of the Annual Report; (D) the numbers of approved TFEs that reached their Expiration Dates or were terminated during the preceding year; and (E) the numbers of approved TFEs that are scheduled to reach their Expiration Dates during the ensuing year;

(ii) Categorization of the submitted and approved TFE Requests to date by broad

categories such as the general nature of the TFE Request, the Applicable Requirements covered by submitted and approved TFE Requests, and the types of Covered Assets that are the subject of submitted and approved TFE Requests;

(iii) Categorization of the circumstances or justifications on which the approved TFEs

to date were submitted and approved, by broad categories such as the need to avoid replacing existing equipment with significant remaining useful lives, unavailability of suitable equipment to achieve Strict Compliance in a timely manner, or conflicts with other statutes and regulations applicable to the Responsible Entity;

(iv) Categorization of the compensating measures and mitigating measures

implemented and maintained by Responsible Entities pursuant to approved TFEs, by broad categories of compensating measures and mitigating measures and by types of Covered Assets;

(v) For each TFE Request that was rejected or disapproved, and for each TFE that

was terminated, but for which, due to exceptional circumstances as determined by the Regional Entity, the Effective Date was later than the latest date specified in Section 5.1.5, 5.2.6, or 9.3, as applicable, a statement of the number of days the Responsible Entity was not subject to imposition of findings of violations of the Applicable Requirement or imposition of Penalties or sanctions pursuant to Section 5.3.

(vi) A discussion, on an aggregated basis, of Compliance Audit results and findings

concerning the implementation and maintenance of compensating measures and mitigating measures, and the implementation of steps and the conduct of research and analyses to achieve Strict Compliance with the Applicable Requirements, by Responsible Entities in accordance with approved TFEs;

(vii) Assessments, by Regional Entity (and for more discrete areas within a Regional

Entity, if appropriate) and in the aggregate for the United States and for the jurisdictions of other Applicable Governmental Authorities, of the Wide-Area impacts on the reliability of the Bulk Electric System of approved TFEs in the aggregate, including the compensating measures and mitigating measures that have been implemented; and



(viii) Discussion of efforts to eliminate future reliance on TFEs. 13.2. Submission of Quarterly Reports by Regional Entities to NERC In order to facilitate timely preparation of the Annual Report, each Regional Entity shall

submit to NERC, within thirty (30) calendar days following the end of each calendar quarter, a report listing (i) the types of Covered Assets with respect to which TFE Requests were approved during such quarter, and (ii) final totals for the quarter of TFE Requests accepted and rejected and TFE Requests approved and disapproved. The reports submitted by the Regional Entities to NERC shall be Confidential Information.

13.3. Due Date for Annual Reports The first Annual Report shall cover the period through June 30, 2011, and shall be filed with FERC and with other Applicable Governmental Authorities no later than 90 days after the end of such calendar quarter. Subsequent Annual Reports shall be filed at one year intervals thereafter. 13.4. Annual Report to be a Public Document; Confidential Appendix It is the intent of this Appendix that the Annual Report be a public document. Therefore, NERC shall prepare the annual report in such a manner that it does not include or disclose any Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information. However, if NERC determines it is necessary to include any Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information in an Annual Report in order to satisfy the information requirements specified in this Appendix or required by FERC or other Applicable Governmental Authorities, such Confidential Information, Classified National Security Information, NRC Safeguards Information or Protected FOIA Information shall be contained in a separate non-public, confidential appendix to the Annual Report. Prior to submitting to FERC or another Applicable Governmental Authority a non-public, confidential appendix that provides specific Confidential Information, Classified National Security Information, NRC Safeguards Information, or Protected FOIA Information of a particular Responsible Entity and identifies the Responsible Entity or one of its Facilities by name, NERC shall provide at least twenty-one (21) days advance notice to the Responsible Entity. The non-public, confidential appendix shall be submitted to FERC and other Applicable Governmental Authorities in accordance with their procedures for receiving confidential, proprietary and other protected information. 13.5. Responsible Entities Must Cooperate in Preparation of Annual Report As specified in Paragraph 220, note 74 of Order No. 706, Responsible Entities must cooperate with NERC and Regional Entities in providing information deemed necessary for NERC to fulfill its reporting obligations to FERC.

Notice of Proposed Revisions to NERC Rules of Procedure Appendix 4D and Request for Comments October 5, 2012

Proposed Revisions to Rules of Procedure Appendix 4D Comments Due: November 19, 2012

The North American Electric Reliability Corporation (NERC) is proposing changes to its Rules of Procedure. NERC requests comments on proposed revisions to the NERC Rules of Procedure Appendix 4D. The comment period begins October 6, 2012 and ends November 19, 2012.

Materials Included in this Request for Comments

• Summary of Proposed Revisions

• Redlined Text of Proposed Revisions to Appendix 4D

Process NERC’s bylaws specify the procedure to be followed in making changes to NERC’s Rules of Procedure. Such changes must be publicly posted for a 45-day comment period before being considered by the NERC Board of Trustees. (Bylaws, Article XI, Section 2.) Such changes must also be approved by the Federal Energy Regulatory Commission before they may take effect in the U.S. No equivalent approval is required from any ERO governmental authority in Canada. The changes, if approved, will take effect on the same date throughout the jurisdictions in which NERC operates. Submission of Comments Comments are due November 19, 2012, and must be submitted electronically to [email protected]. NERC intends to submit these changes to the NERC Board of Trustees for approval at its December 19, 2012 meeting. Although the comment period does not close until November 19, 2012, commenters are respectfully requested to submit their comments sooner, if possible, in order to provide additional time for NERC staff and the Regional Entities to consider them. For further information, please contact Rebecca Michael at [email protected].




Follow-Up Activities from the Arizona-Southern California Outage

Action Information

Background On May 1, 2012, FERC and NERC issued the “Arizona-Southern California Outages on September 8, 2011” inquiry report (Joint Report). On July 26, 2012, NERC President and CEO Gerry Cauley sent a letter to WECC CEO, Mark Maher, requesting a detailed report outlining near-term remediation actions completed or in progress to date, and plans for additional actions going forward. Subsequently, WECC submitted a Preliminary Response Report to NERC on August 31, on which NERC commented on September 13. WECC sent its Response Report on September 28, incorporating changes based on the comments received from NERC and providing updates on the activities that address the 27 recommendations from the Joint Report, as well as the eight broader systemic issues discussed in the July 26 letter.

Melanie Frye, vice president, planning and operations, WECC, and Dave Nevius, senior vice president, NERC, who was NERC's point person on the Joint Report and is leading the follow-up activities for NERC, will brief the MRC on the status of activities both in WECC and in the other Regional Entities. Enclosed Attachments

1. Mark Maher’s email transmitting WECC’s September 28, 2012 Response Report addressing the issues in Mr. Cauley’s July 26 letter.

2. WECC September 28, 2012 Response Report.

1

Tina Buzzard

Subject: FW: Response to the "Arizona-Southern California Outages on September 8, 2011" Report

From: Maher, Mark [mailto:[email protected]] Sent: Friday, September 28, 2012 6:41 PM To: Gerry Cauley Cc: Dave Nevius; '[email protected]' Subject: Response to the "Arizona-Southern California Outages on September 8, 2011" Report

September 28, 2012 Gerry Cauley President and CEO North American Electric Reliability Corporation 3353 Peachtree Road NE, Suite 600 North Tower Atlanta, GA 30326 RE: Response to the “Arizona-Southern California Outages on September 8, 2011” Report Dear Gerry: On July 26, you requested a detailed report outlining near-term remediation actions completed or in progress to date, and plans for additional actions going forward. Subsequently, WECC submitted a Preliminary Response Report to you on August 31, and received comments back on September 14. The attached Response Report incorporates the comments received and provides updates on the activities that address the 27 recommendations from the Joint Report, as well as the eight broader systemic issues you discussed in your July 26 letter. This Response Report has not changed, directionally, from the August 31 Preliminary Response Report; rather, it has been fine-tuned, clarifications have been made, and activities have been added in light of the comments received. Specifically, some of the significant changes have been:

ORG1: Update on strategic planning initiative on structure, governance, and funding based on the September 2012 Board meeting

ORG3: Added information on future meetings on the role of the Path Operator

ORG7: Added activity to provide education on the Path Rating process

RC3: Added a request for Transmission Operators to provide a list of sub-100-kV facilities that should be monitored

RC9: Added creation of a task force to work on interchange issues, and added milestones

2

RC18: Added activity for the RC to share real-time data through Inter-control Center Communications Protocol (ICCP)

O&P10: Changed activity to benchmark dynamic models against actual data

O&P20: Changed activity to include a default generator tripping model to base cases rather than generator-specific models. This moved the completion from 2015 to 2012

O&P22: Added activity to consider the Real-time Digital Simulation (RTDS) tool

NERC12: Added suggested NERC activity to consider planning function registration gap issues

General: Dates have been modified based on comments and additional information

WECC and its member utilities are committed to reliability and have been working diligently since the event and the issuance of the Joint Report to address the underlying issues and the specific recommendations contained therein. WECC will continue to apprise NERC and FERC of progress made on these activities quarterly. WECC appreciates the opportunity to report on these activities and looks forward to coordinating with NERC on these and any continent-wide activities. Sincerely,

Mark W. Maher Chief Executive Officer Cc: Dave Nevius Regional Executive Managers Group

Document name Response to the “Arizona-Southern California Outages on September 8, 2011” Report

Category ( ) Regional reliability standard ( ) Regional criteria ( ) Policy ( ) Guideline ( X) Report or other ( ) Charter

Document date 9/28/2012

Adopted/approved by

Date adopted/approved

Custodian (entity responsible for maintenance and upkeep)

WECC Staff

Stored/filed Physical location: Web URL:

Previous name/number (if any)

Status ( ) in effect ( ) usable, minor formatting/editing required ( ) modification needed ( ) superseded by _____________________ ( ) other _____________________________ ( ) obsolete/archived)

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

Response to the “Arizona-Southern California Outages on September 8, 2011”

Report

By

WECC Staff

Western Electricity Coordinating Council

September 28, 2012

September 28, 2012 3

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 ST • 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 35 3 • F X 8 0 1 . 5 8 2 . 3 9 1 8

Response to the “Arizona-Southern California Outages on September 8, 2011” Report

1 Executive Summary

This Response Report by the Western Electricity Coordinating Council (WECC) has been prepared in response to the North American Electric Reliability Corporation (NERC) and the Federal Energy Regulatory Commission (FERC) Report on the Arizona-Southern California Outages on September 8, 2011 (Joint Report) published May 1, 2012. This Response Report lists activities completed or underway in response to the 27 findings identified in the Joint Report (Table 4). In addition it provides activities that address the eight additional systemic concerns described in a letter dated July 26, 2012 from Gerry Cauley, NERC President and CEO, to Mark Maher, WECC CEO (Table 5).

WECC and its member utilities are committed to reliability and have been working diligently since the event and the issuance of the Joint Report to address the underlying issues and the specific recommendations contained therein. Significant progress has already been made in many areas. There are 51 WECC activities and 69 member activities currently underway, all with defined timelines that reflect a sense of urgency. However, while WECC recognizes the need to resolve these issues expeditiously it must ensure that well-reasoned, technically sound actions are not compromised in the interest of time. Consequently, the timeframe for completion of the activities ranges from 2011 – 2015.

The WECC activities that address the recommendations and the systemic concerns are divided into four main sets: Organization1 (ORG), Reliability Coordinator (RC), Operations and Planning (O&P), and Compliance (CPL). The most significant activity in the ORG area is a strategic planning process that is proposing future options for the structure, governance, and funding mechanism(s) of WECC. Other organizational activities include reviewing data sharing, reviewing standards, the creation of a Vice President of Reliability Coordination position, and the consideration of creative ways to ensure sufficient, qualified staff resources.

The most significant RC activity currently underway is the work of the RC Task Force (RCTF); a task force created at the direction of the WECC Board of Directors (Board). The purpose of the RCTF is to evaluate staffing, tools, and training to determine effectiveness; and to develop recommendations for changes necessary to fulfill WECC’s

1 Activities undertaken by WECC's management and Board.

http://www.nerc.com/files/AZOutage_Report_01MAY12.pdf



mission. Additional RC activities include improving processes and tools, facilitating greater data sharing, and increasing staffing.

The O&P activities include developing processes and guidelines to help facilitate consistency and coordination among entities in the planning and operations horizons. These activities also include reviewing the role and coverage of the Planning Coordinator and improving the WECC base cases to provide high-quality data to the membership.

The focus of the Joint Report and this Response Report is not on compliance with mandatory standards. However, there are some activities that WECC’s Compliance group is undertaking to improve the ability of the Compliance Monitoring and Enforcement Program to help address reliability concerns. These include adding standards to the audit scope, documenting “areas of concern” in audit reports, discussing high-level trends and issues with the RC, and coordinating with NERC to improve processes.

Additionally, seven member utilities have provided WECC with 69 activities that they are currently performing as a result of the event and the Joint Report. These activities indicate that several members are improving visibility of external and sub-100-kV elements in their models, improving sharing of data, implementing state estimators and real-time contingency analysis, and generally reviewing and improving processes and practices.

WECC also recognizes that there are several issues identified in the Joint Report that transcend the Western Interconnection and may be relevant to entities continent-wide. Consequently, WECC has identified 12 issues where, in WECC’s opinion, NERC should take the lead. WECC is committed to participate and coordinate with NERC on all such actions.

While several issues identified in the Joint Report required compliance with associated mandatory reliability standards, the focus of this Response Report is on reliability. Taking this into consideration, WECC strongly encourages Registered Entities to review their systems, practices, and processes not only for compliance with the language of the requirement, but also for the intent of the standards, and the best interest of the reliability of the Interconnection.

WECC commends the commitment of its membership and Registered Entities to improving reliability and addressing the recommendations of the Joint Report.

2 Background

The Joint Report identified 27 findings and recommendations relating to situational awareness; next-day planning; seasonal planning; near- and long-term planning; impact of sub-100-kV facilities; and Interconnection Reliability Operating Limits (IROL). Many of



these recommendations affect not only the Registered Entities that were involved in the event, but extend to all Registered Entities across the continent.

On June 5, 2012, WECC received a letter from David Nevius, Senior Vice President of NERC, asking follow-up questions associated with the 27 recommendations from the Joint 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. On July 20, 2012, WECC posted a high-level summary of the survey results on its website.

On July 26, 2012, WECC received a letter from Gerry Cauley in which he reinforced the importance of the recommendations from the Joint Report and identified an additional eight systemic concerns. In his letter, Mr. Cauley requested that WECC provide a comprehensive Response Report outlining near-term remediation actions completed or in progress to date, and plans for additional actions.

WECC and NERC subsequently agreed that WECC would send a Preliminary Response Report to NERC for comment on August 31, 2012 with an updated Response Report posted by WECC on September 30, 2012. WECC received comments from NERC on September 14, 2012 that are addressed in this version.

3 Activities

Many of the activities underway at WECC and the Registered Entities in the Western Interconnection address the multiple recommendations and systemic concerns. As such, Sections 3.1 and 3.2 of this Response Report are laid out to identify all activities currently underway. In addition, WECC and its stakeholders have identified that some of the recommendations have ramifications for the entire North American Bulk Electric System (BES) and believe that these should be addressed by NERC. Although WECC is taking action on all recommendations, Section 3.3 identifies the areas that WECC believes should be addressed by NERC. To avoid any duplication of effort, WECC proposes to coordinate with NERC on all of these continent-wide issues.

Collectively, the activities in Sections 3.1 to 3.3 address the recommendations from the Joint Report and the systemic concerns identified in Mr. Cauley’s letter. Section 3.4 cross-references the activities listed in Sections 3.1 to 3.3, to the recommendations from the Joint Report and the systemic concerns identified in Mr. Cauley’s letter.

http://www.wecc.biz/Lists/SWEvent/NewForm.aspx

http://www.wecc.biz/library/WECC%20Documents/Publications/Summary%20of%20Sept%208%20Survey%20Result.pdf

http://www.wecc.biz/library/WECC%20Documents/Publications/Gerry%20Cauley%20WECC%20July%2026%202012.pdf

http://www.wecc.biz/library/WECC%20Documents/Publications/Preliminary%20Response%20Report%20to%20Sept%208%20version08312012.pdf

http://www.wecc.biz/library/WECC%20Documents/Publications/Preliminary%20Response%20Report%20to%20Sept%208%20version08312012.pdf



3.1 WECC Activities

Table 1 provides a summary of all of the WECC activities completed, underway, and planned that are related to the event on September 8, 2011. These activities are being performed by WECC staff, committees, and the WECC Board.



Activity Legend: ORG ...... WECC Management and Board

RC ......... Reliability Coordinator Staff

O&P ...... Operations and Planning Staff

CPL ....... Compliance Staff

Table 1: WECC Activities

Activity Status Estimated Completion Date

Organizational (ORG) Activities

ORG1 Examination of potential Structural and Governance Changes In Progress June 27, 2013

ORG2 WECC review of all Data Sharing Practices/ Policies/Agreements

In Progress March 30, 2013

ORG3 Summer Preparedness Meeting with executives of Arizona and Southern California Entities

COMPLETE August 30, 2012

ORG4 Create new position for Vice President of Reliability Coordination.

COMPLETE May 21, 2012

ORG5 Review of Standards for Areas of Improvement In Progress December 31, 2012

ORG6 Human Resource Development In Progress December 31, 2013

ORG7 Provide education on Path Rating Process In Progress December 31, 2012

Reliability Coordinator (RC) Activities

RC1 Share Next-Day Studies COMPLETE August 23, 2012

RC2 Signatories of Universal Non-Disclosure Agreement In Progress December 31, 2012

RC3 Sub-100-kV Facility Identification In Progress June 28, 2013

RC4 Share Outage Data with TOPs COMPLETE August 23, 2012





RC5 Share RC State Estimator and Real-Time Contingency Analysis (RTCA) with TOPs

Not yet started To be determined

RC6 Enhanced System Operating Limit (SOL) Methodology – Phase I

COMPLETE June 4, 2012

RC7 Enhanced SOL Methodology – Phase II In Progress June 30, 2013

RC8 RC Task Force Evaluation In Progress December 31, 2014

RC9 Improve RC Forecasted Interchange In Progress December 31, 2013

RC10 Additional formats of Next-Day Studies In Progress October 12, 2012

RC11 Defined roles and responsibilities in SOL Exceedances In Progress June 28, 2013

RC12 SOL Reporting Tools In Progress December 31, 2012

RC13 Loss of Real-time Tools Notification In Progress October 31, 2012

RC14 RC Phase Angle Tools In Progress September 30, 2013

RC15 Coachella Valley Transformers in RTCA COMPLETE September 16, 2011

RC16 2013 Headcount In Progress December 31, 2013

RC17 Revise Internal Operating Procedures In Progress November 12, 2012

RC18 Real-time ICCP Data Hub In Progress March 1, 2013

Operations and Planning (O&P) Activities

O&P1 Survey of Western Interconnection Practices In Progress October 31, 2012

O&P2 Best Practices for Next-Day Studies In Progress January 31, 2013

O&P3 Consistent Mechanism for Seasonal Planning In Progress June 1, 2014

O&P4 Ensure Coverage of PCs In Progress December 31, 2013





O&P5 Model Relays and RAS in Base Cases In Progress December 31, 2015

O&P6 RASRS review additional Tie-line Schemes and Safety Nets In Progress November 29, 2012

O&P7 Coordination of Transmission Planning Assessments In Progress June 30, 2013

O&P8 Base Case Coordination System In Progress July 31, 2013

O&P9 Relay Operations Guideline In Progress January 31, 2013

O&P10 Benchmark TP Models Against September 8 Event In Progress December 31, 2013

O&P11 Sharing Real-Time Data among TOPs In Progress January 31, 2013

O&P12 Distribute the NERC Real-Time Tools Best Practices Task Force Report (RTTBPTF).


O&P13 Develop Real-Time Tools Guideline In Progress January 31, 2013

O&P14 Real-Time Tools Training Guideline In Progress January 31, 2013

O&P15 Address discrepancies between Planning and Operations Models

In Progress June 30, 2014

O&P16 Guideline on sub-100-kV Elements in Models In Progress October 31, 2013

O&P17 Comprehensive Review of RAS In Progress November 28, 2012

O&P18 Guideline on Post-Contingent Plans In Progress January 31, 2013

O&P19 White Paper on Generator Acceleration Controls In Progress June 30, 2014

O&P20 Generator Tripping in Base Cases In Progress October 12, 2012

O&P21 Review of Elements to add to BES In Progress January 31, 2014

O&P22 Consider Real-Time Digital Simulation In Progress June 30, 2013





Compliance (CPL) Activities

CPL1 Add Standards to Audit Scope COMPLETE May 29, 2012

CPL2 Add “Areas of Concern” to Audit Reports COMPLETE September 24, 2012

CPL3 Meetings between Compliance and the RC In Progress October 31, 2012

CPL4 Coordinate with NERC on Issues In Progress February 28, 2013



3.1.1 Examination of Potential Organizational and Governance Changes (ORG1)

The Board annually undertakes a strategic planning session at its September meeting. Subsequent to the 2011 strategic planning session; the WECC Board, with input from WECC senior management, developed a revised Three-to-Five Year Strategic Plan that identifies mission and vision statements focusing on WECC’s reliability role in the Western Interconnection. The Board approved the revised plan at its December 2011 meeting.

WECC’s mission is to promote and foster a reliable and efficient Bulk Electric System. As WECC carries out this mission, it aspires to lead stakeholders in the Western Interconnection to achieve optimal system reliability, be the premier source of unbiased information, and serve as the trusted thought leader for the Western Interconnection.

WECC was formed in 2002 in anticipation of mandatory standards and was structured to maintain a trade association framework and governance. Since then, WECC’s role and scope of activities has grown with the introduction of mandatory reliability standards in 2007 and in 2009, with the assumption of the Reliability Coordinator function for the Western Interconnection.

In addition, subsequent to the 2011 strategic planning session, several challenges to WECC’s reliability mission have been identified and, as a result, the September 6-7, 2012 planning session considered the future structure, governance, and funding mechanism(s) of WECC.

PROJECT SCOPE

Phase I: (July – September):

1. Identify challenges

2. Identify options for:

a. Structure

b. Governance

c. Funding mechanism(s)

3. Board decision on recommended options

Phase II: (September – December)

1. Three-year budget assessment for the recommended organization and associated governance and funding mechanism(s)

2. Additional governance considerations (e.g., Bylaws)

At the September 6-7 strategic planning session, the Board passed four resolutions regarding the future structure, governance, and funding of WECC.

http://www.wecc.biz/committees/BOD/20120905/Lists/Exhibits/1/Structure-funding-governance-resolutions.pdf



These resolutions included:

1. pursuing bifurcation into two companies (one Regional Entity and one Non-Regional Entity);

2. developing a governance model with an independent board and strong member advisory committee for the Regional Entity;

3. developing a governance model with a small hybrid board for the Non-Regional Entity; and

4. developing a funding mechanism including continuation of Federal Power Act Section 215 funding for the Regional Entity and a tariff for the Non-Regional Entity.

Materials developed pursuant to these resolutions will be presented to the December 2012 Board meeting.

Milestone Status Expected Completion Date

Draft strategic planning slides posted for stakeholder comment


Draft strategic planning white paper posted COMPLETE August 24, 2012

Informational Webinar COMPLETE August 29, 2012

Strategic Planning Session Phase I COMPLETE September 6-7, 2012

Develop Phase II materials In Progress November 28, 2012

Strategic Planning Session Phase II Scheduled December 5-7, 2012

Develop any additional materials Not Started May 28, 2013

Annual Membership Meeting and vote Scheduled June 27, 2013

http://www.wecc.biz/committees/BOD/20120829/Lists/Minutes/1/Presentation%20v13%208-27-2012.pdf

http://www.wecc.biz/committees/BOD/20120829/Lists/Minutes/1/WECC%20STRATEGIC%20PLANNING%20WHITE%20PAPER%20FINAL%20-%20August%2023.pdf

http://www.wecc.biz/committees/BOD/20120829/default.aspx?InstanceID=1



3.1.2 WECC Review of all Data Sharing Practices/Policies/Agreements (ORG2)

WECC is reviewing all relevant data sharing practices, policies, and agreements, including, but not limited to:

• Data Information Availability Policy

• Reliability Information Sharing Policy

• Universal Non-Disclosure Agreement

• WECC Policy for WECC Reliability Coordinator (RC) Data Request

• Guideline for Reliability Coordinator (RC) Data Requests

• Criteria for Physical Connection to the WECC Operations Network

The initial stage of the review will include a legal summary of the purpose and scope of each of the documents. The second stage will be a review by technical staff of whether there are duplications or gaps in coverage. Once the review is complete, there will be a discussion of next steps.


Legal Review of existing policies COMPLETE August 23, 2012

Technical review of existing policies In Progress December 31, 2012

Development of next steps and recommendations

Not Started March 30, 2013

3.1.3 Summer Preparedness Meeting with Executives of Arizona and Southern California Entities (ORG3)

Prior to the summer operating season, WECC convened a meeting of operational leadership from the entities responsible for serving critical loads and operating transmission facilities in the Pacific Southwest. The entities in attendance were Arizona Public Service Company (APS), California Independent System Operator (CAISO), Comisión Federal de Electricidad (CFE), Imperial Irrigation District (IID), Los Angeles Department of Water and Power (LADWP), Southern California Edison (SCE), San Diego Gas & Electric (SDG&E), Western Area Power Administration (WAPA), and WECC.

The purpose of the meeting was to collaborate and address any necessary actions required to assure the reliability of the BES in the Western Interconnection during the summer 2012 season and beyond. The meeting provided the opportunity for the group

http://www.wecc.biz/library/WECC%20Documents/Business%20and%20Governance%20Documents/Policies/Data%20Information%20Availability%20Policy.pdf

http://www.wecc.biz/library/WECC%20Documents/Business%20and%20Governance%20Documents/Policies/Reliability%20Information%20Sharing%20Policy.pdf

http://www.wecc.biz/awareness/Reliability/Documents/FINAL%20WECC%20WSM%20License.pdf

http://www.wecc.biz/awareness/Reliability/RPIC/Documents/WECC%20RC%20Data%20Request%20Policy%203-21-2011.pdf

http://www.wecc.biz/awareness/Reliability/RPIC/Documents/WECC%20RC%20Data%20Request%20-%20Attachment%201%203-21-2011.pdf

http://www.wecc.biz/committees/StandingCommittees/OC/CIIMS/Shared%20Documents/Criteria%20For%20Physical%20Connection%20to%20the%20WON.pdf



to better understand the roles and responsibilities of the WECC RC function, Balancing Authorities (BA), Transmission Owners (TO) and Transmission Operators (TOP).

A follow up meeting was held on August 30, 2012 to discuss lessons learned and assess the summer operating season. The general consensus was that coordination and communication have improved. There was continuing discussion regarding clarifying the role of the Path Operator, including the potential to implement contractual relationships. There was also discussion about ways to use tools such as RTCA to improve accuracy of system operating limits, rather than relying solely on conservative nomograms in real-time. There is executive support to continue this series of meetings and hold a summer preparedness meeting in spring 2013.

Arizona Public Service (APS) will facilitate further discussions to identify the issues with the Path Operator roles, responsibilities, and authorities. APS anticipates hosting the first discussion in October.


Summer preparedness meeting COMPLETE May 31, 2012

Follow-up meeting COMPLETE August 30, 2012

Continue follow-up meetings ONGOING

COMPLETE

3.1.4 New Position for Vice President of Reliability Coordination (ORG4)

The WECC Reliability Coordination function now encompasses nearly half of WECC’s budget and staff. To bring the necessary focus and direct line of sight for that function, WECC created the new position of Vice President, Reliability Coordination and included it in the WECC Executive Steering Team (WEST). John McGhee was appointed to this position on May 21, 2012.

Milestone Status Completion Date

Vice President appointed COMPLETE May 21, 2012

COMPLETE

3.1.5 Review of Standards for Areas of Improvement (ORG5)

WECC has observed that, in some cases, NERC standards do not explicitly address the actions identified in several of the recommendations. For example, while some standards say that studies must be performed, they do not identify what conditions or



parameters must be used. Other standards require that entities “coordinate” but do not define what level of coordination is expected for various aspects.

In some cases, WECC believes the level of detail included in standards is appropriate, and, through the O&P activities listed below, is developing guidelines that identify best practices. In other cases, changes may be necessary to address reliability concerns. In those instances WECC will develop Standard Authorization Requests (SAR).

WECC will coordinate SARs and gap issues with NERC and their Reliability Issues Steering Committee (RISC).

The WECC Standards Department and Compliance Department are working together on a thorough review of standards associated with the recommendations. This review will include:

• identification of standards related to the recommendations in the Joint Report;

• identification of areas where standards do not explicitly require the actions in the recommendations of the Joint Report

• analysis of the current and previous monitoring activities as specified in previous Compliance Monitoring and Enforcement Program Implementation Plans; and

• suggestions for future actions.

WECC has posted the preliminary analysis of NERC standards and will continue to review and work with NERC on follow-up actions.


Meeting between Standards and Compliance Departments


Review all standards associated with Recommendations

COMPLETE September 28, 2012

Preliminary analysis posted and provided to NERC


Review analysis and develop action plans in collaboration with NERC

Not Started December 31, 2012

Submit any applicable SARs Not Started March 31, 2013

http://www.wecc.biz/library/WECC%20Documents/Publications/Sept%208%20Documents/Standards%20Assessment.pdf



3.1.6 Human Resource Development (ORG6)

WECC has discussed the need for qualified resources to meet the continuing demands of operating the BES with utility executives. This includes the critical skill sets of system operators, engineers, and analysts that are in high demand. WECC has had preliminary discussions with some utilities about the possibility of resource sharing or cross training opportunities, as well as the potential to work with educational institutions to develop the necessary skill sets in future employees. The issue of the aging workforce in the utility industry is well known and creates an opportunity for WECC and the industry to work together to broaden the pool of qualified resources.


Discussion with executives In Progress March 2013

Action Plan Not Started December 2013

3.1.7 Provide Education on Path Rating Process (ORG7)

The WECC Path Rating process is described in the Overview of Policies and Procedures for Project Coordination Review, Project Rating Review and Progress Reports. WECC will provide an educational webinar for interested parties, including NERC and FERC, on the Path Rating process and its use in real-time operations.


Identify appropriate Subject Matter Experts In Progress October 31, 2012

Identify convenient time In Progress October 31, 2012

Provide webinar Not Started December 31, 2012

3.1.8 Share Next-Day Studies (RC1)

The RC staff performs a daily next-day study of the expected peak load conditions for the following day. The study is started in the morning with the setup of the study case. The study case starts as a snapshot from the WECC RC state estimator from the previous day’s peak, which provides a very reasonable initial setup of generation, load, and actual transmission and generation outages. The next-day study inputs include scheduled transmission and generation outages, load forecast, interchange forecast, and expected generation. The study process takes several hours to complete and is typically finished in the late afternoon. The next-day study inputs and study results are now shared on WECCRC.org with all BAs and TOPs that have signed the WECC Synchrophasor and Operating Reliability Data Sharing Agreement (Universal Non-Disclosure Agreement (NDA)). This sharing began July 16, 2012.

http://www.wecc.biz/library/Documentation%20Categorization%20Files/Guidelines/ProjectCoordination_ProjectRating_ProgressReports_approved%203-11.pdf





WECCRC.org also allows signatories of the Universal NDA to post their own next-day studies and view the studies that have been posted by other BA and TOP signatories.


Notice of intent to publish study inputs and results


Study inputs and results published on WECCRC.org

COMPLETE July 16, 2012

Allow BA and TOP signatories of the Universal NDA to post and view each others’ next-day studies


COMPLETE

3.1.9 Signatures of Universal NDA (RC2)

WECC developed the Universal NDA to facilitate the sharing of synchrophasor data and operating reliability data with BAs, TOs, TOPs, and RCs, while protecting the confidentiality of the data. Sharing this type of data will provide more visibility and consistency of data availability to signatories. As of September 20, 2012, 92 percent of potential signatories have executed the Universal NDA.


Universal NDA Distributed COMPLETE March 6, 2012

Initial signature deadline COMPLETE March 31, 2012

Washington state signatory issue resolved COMPLETE September 14, 2012

Anticipated signature from all parties In Progress December 31, 2012

3.1.10 Sub-100-kV Facility Identification (RC3)

The RC model currently includes facilities operated at voltages greater than 100 kV, as well as some sub-100-kV facilities that may have an impact on the BES.

The RC is seeking to identify facilities with at least one terminal below 100 kV that may have an impact on the BES. The study involves identifying low-voltage systems that may experience significant flow-through following the loss of parallel higher voltage facilities. The study is being conducted in two phases:



Phase I study: performed using the WECC RC’s West-wide System Model (WSM).

Phase II study: will be performed using WECC’s planning models.

In conjunction with the Phase I effort, the WECC RC will request that the TOPs provide a list of sub-100-kV facilities that the TOPs feel should be monitored due to the risk of flow through the lower-voltage systems during outage conditions. After Phase I is complete, the WECC RC will enable monitoring in the WECC RC Energy Management System (EMS) for facilities operated at less than 100 kV that are already modeled in the WSM. After Phase II is complete, the WECC RC will identify additional facilities that need to be added to the WSM. The WECC RC EMS models will then be updated to include the identified facilities. After each phase, the RC will seek comment from the TOPs on inclusion of the lower-voltage facilities identified as needing to be monitored in the WECC RC EMS.


Phase I Analysis In Progress October 12, 2012

Phase I Comment period with TOPs Not Started November 12, 2012

Update existing facility monitoring in WECC RC EMS

Not Started November 19, 2012

Phase II Analysis Not Started January 31, 2013

Phase II Comment period with TOPs Not Started February 28, 2013

Update WECC RC EMS models to include additional lower voltage facilities

Not Started June 28, 2013

3.1.11 Share Outage Data with TOPs (RC4)

WECC has enabled all signatories of the Universal NDA to have permission to view its Coordinated Outage System. This provides transparency of scheduled outages throughout the Western Interconnection. A page will be added to the WECCRC.ORG site that explains this process and how to sign up for an account to view the information.




Permissions established COMPLETE August 22, 2012

Page added to WECCRC.ORG COMPLETE August 23, 2012

COMPLETE

3.1.12 Share RC State Estimator and Real-Time Contingency Analysis with TOPs (RC5)

The WECC RC performs real-time state estimation and contingency analysis using the WSM, which represents the entire Western Interconnection. The state estimator applies nearly 100,000 measurements to the WSM to accurately estimate the current state of the power system, including all equipment flows, voltages (magnitude and angle), and injection megawatts/Mvars (from units, loads, or shunt devices). Contingency analysis uses the latest state estimator solution to determine if the system is in an N-1 secure state. Over 7,500 contingencies are executed every five minutes to determine the expected state of the power system following each of the contingencies. To improve the visibility of TOPs, the WECC RC is developing a process by which to share information from these tools. This process will be developed in two steps:

1. Provide a method to allow BAs and TOPs access to actual RC real-time state estimator, contingency analysis, and other situational awareness-enhancing real-time tools.

2. Develop a feedback process to identify and correct issues identified through TOP and BA review of results.


Access to actual state estimator and RTCA Not Started To be determined

Feedback process Not Started To be determined

3.1.13 Enhanced System Operating Limit (SOL) Methodology – Phase I (RC6)

The RC made significant revisions to the document, WECC RC System Operating Limits Methodology for the Operations Horizon. This process describes the WECC RC’s protocols and expectations related to establishing and communicating SOLs and IROLs. The changes to this process include adding a clear process for identifying the subset of SOLs that qualify as IROLs in real-time, and a clear definition that an SOL includes all operating limits such as the facility thermal limits, voltage limits, stability limits, and Transmission Path limits. System performance expectations were defined to make it

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/WECC%20RC%20-%20SOL%20Methodology%20for%20the%20Operations%20Horizon.pdf

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/WECC%20RC%20-%20SOL%20Methodology%20for%20the%20Operations%20Horizon.pdf



clear that all reliability-based “operating limits,” including facility limits, are SOLs. In doing so, this takes the number of SOLs that the RC System Operator must monitor from a few hundred to several thousand. The SOL Methodology makes it clear that there is an expectation for TOPs to operate within all reliability-based operating limits as they are all SOLs.


Enhanced methodology posted COMPLETE April 2, 2012

Educational outreach COMPLETE April 30, 2012

Methodology implemented COMPLETE June 4, 2012

COMPLETE

3.1.14 SOL Methodology – Phase II (RC7)

The RC is now working on further refining the WECC RC SOL Methodology in Phase II. WECC has identified 19 key issues for Phase II and has populated teams to address each issue. The key issues identified are:

1. Distinguishing between the planning horizon and operations horizon

2. Definitions and terms

3. Appropriateness of using planning criteria for establishment of SOLs in the operations horizon

4. Identification of credible multiple-facility contingencies

5. Determining megawatt load-impact level for defining IROLs in WECC

6. Determining IROLs in the operations horizon

7. Outage SOL/IROL determination

8. Awareness and impact of sub-100-kV facilities

9. Need to conduct full contingency analysis

10. Seasonal SOL coordination

11. Acceptable process for updating/coordinating changes to SOLs/IROLs

12. Benchmarking the WECC RC SOL Methodology with other RCs

13. Study margins

14. Subregional differences within WECC

15. Differences between Path Rating and Path SOL

16. Interface, transfer path, and system interactions 17. Impact of path/facilities/interfaces/systems when determining SOLs/IROLs

18. Controlled separation schemes

19. Implementation Plan for Phase II of the SOL Methodology for the Operations Horizon




Identify key issues COMPLETE August 2012

Resolve key issues In Progress December 31, 2012

New methodology posted In Progress March 29, 2013

Educational outreach Not Started May 31, 2013

Methodology implemented Not Started June 30, 2013

3.1.15 RC Task Force Evaluation (RC8)

The WECC Board established the RCTF to evaluate the RC staffing, tools, and training to determine the current effectiveness and to prepare recommendations for changes necessary for the WECC RC to fulfill its mission and responsibilities. The RCTF met on August 15, 2012 to review the current staffing levels and to work on identifying additional staff necessary to fulfill the recommendations from the Joint Report. Work is in progress to determine how best to improve the WECC RC’s wide area view with a more in-depth understanding of the BA and TOP tools needed to provide more focused directives and improve the coordination of operational planning.


RC Task Force established COMPLETE June 19, 2012

Recommendation report In Progress December 7, 2012

Begin to implement RCTF recommendations Not Started December 31, 2012

Complete RCTF recommendations Not Started December 31, 2014

3.1.16 Improve RC Forecasted Interchange (RC9)

The RC is working to improve how study data, in particular unit commitment data and the forecasted interchange, is obtained and used. Having better interchange and unit commitment data will make the studies far more accurate. The RC is working with BAs to both identify the reasons for errors in forecasts and improve the unit commitment data that are currently provided. Some of those BAs have already made incremental improvements to the data and are submitting the improved forecasted interchange data to the RC for use in next-day studies. A task force will be created to identify metrics that define study quality, and to review and address input data issues.




Create a task force to monitor and improve RC and TOP study data and study results

In Progress December 31, 2012

Address unit commitment data issues for units greater than 200 MW


Address unit commitment data issues for units less than 200 MW

Not Started September 30, 2013

Validate interchange data following improvement of unit commitment data; address errors identified


3.1.17 Additional Formats of Next-day Studies (RC10)

The RC is working on providing its next-day studies in PTI format. This format will allow TOPs to review the completed RC next-day study in power flow tools such as Power System Simulator for Engineering (PSS\E) and Positive Sequence Load Flow (PSLF). This will help the RC and TOPs significantly when they review next-day study case issues as it will allow the TOPs to look into studies executed by the RC. The next-day study cases will be posted to the WECCRC.org site for sharing, with signatories of the West-wide System Model License Agreement.


Studies shared in PTI format In Progress October 19, 2012

3.1.18 Defined Roles and Responsibilities in SOL Exceedances (RC11)

The RC is developing individual Operating Guides for each WECC Transfer Path and identified Transmission Path to further define the roles and responsibilities of RC System Operators when mitigating an SOL exceedance. RC personnel will coordinate with applicable BA/TOPs to develop Operating Guides that include a description of operating characteristics and identify viable mitigating actions under normal and emergency conditions.


Develop Operating Guides In Progress June 28, 2013



3.1.19 SOL Reporting Tools (RC12)

The RC is developing tools to identify and report the occurrence of actual and expected post-contingency SOL exceedances. The RC will develop a corresponding process to notify responsible entities of these events to facilitate discussion and determine corrective actions.


Develop Reporting Tools In Progress December 31, 2012

Develop notification process In Progress December 31, 2012

3.1.20 Loss of Real-Time Tools Notification (RC13)

One gap identified in the survey was that nearly half of responding TOPs do not have a formal procedure to notify the RC for the loss of real-time tools. As a result, the RC is working on modifying the WECC RC Data Request to include a telephone notification requirement for loss of real-time data, tools, or applications that reduce the RC System Operator’s situational awareness of the BES.


Modify WECC RC Data Request In Progress October 31, 2012

3.1.21 RC Phase Angle Tools (RC14)

The WECC RC is working on identifying excessive phase angles using several types of tools and data. Currently, the real-time state estimator can estimate phase angles exceeding a defined limit for a small set of transmission lines. Similarly, the RTCA identifies post-contingent phase angle pairs that exceed a defined limit for the same set of Southwest transmission lines. The RC will evaluate additional transmission lines for monitoring phase angle pairs.

The WECC RC is also involved in the Western Interconnection Synchrophasor Project (WISP), which will include direct measurement of phase angles through Phasor Measurement Units (PMU). More than 300 PMUs are being installed in key locations across the Western Interconnection.




State estimator approximates phase angle differences for some transmission lines


RTCA calculates post-contingent phase angle differences for some transmission lines


Additional transmission lines are included in the state estimator and RTCA phase angle calculations


WISP completed In Progress September 30, 2013

3.1.22 Coachella Valley Transformers Flagged in RTCA (RC15)

On September 8, 2011, the Coachella Valley transformers were modeled in the RC’s RTCA; however, they were not flagged or alarmed. Shortly thereafter, the RC flagged and alarmed these transformers in RTCA.


Flag Coachella Valley transformers in RTCA COMPLETE September 16, 2011

COMPLETE

3.1.23 2013 Headcount (RC16)

A net of 18 new positions are being added in the 2013 WECC Business Plan and Budget, including 10 unbudgeted positions that are expected to be hired in 2012. The additional headcount are associated with adding a lead Reliability Coordinator and an EMS engineer on each shift; and increased RC responsibilities including workload created by modified standards, increased data sharing, and other responsibilities. WECC is committed to hiring well-qualified individuals and providing sufficient training to assure that they fully understand the operation of the Western Interconnection.




Budget approved by WECC Board COMPLETE June 26, 2012

Budget approved by FERC In Progress October 30, 2012

Positions filled In Progress December 31, 2013

3.1.24 Revise Internal Operating Procedures (RC17)

The WECC RC has revised its internal operating procedures to include specific instructions for determining viable mitigation plans, and revised the procedures “Monitoring of Disturbance Control Performance,” “Monitoring of System Frequency and BA Performance,” “WECC Communication Protocol,” and “Monitoring of SOL and IROL violations,” and created the new procedure “Emergency Operations Procedure.” Each revised procedure requires the RC System Operator to issue directives specific to circumstances and system conditions. Reliability Coordinator Directives should include options previously discussed with the recipient, if possible, and times for completion of the action by the recipient.


Revised Procedures besides SOL/IROL COMPLETE August 21, 2012

Revised Procedures posted and noticed to membership


Revised Procedure on SOL/IROL In Progress October 12, 2012

Operator training on procedures besides SOL/IROL completed


Operator training on procedure on SOL/IROL completed


3.1.25 Real-time ICCP Data Hub (RC18)

The WECC RC is moving forward with real-time data sharing using the WECC Extra High Voltage (EHV) ICCP data exchange servers. The real-time ICCP data points will be made available in a prioritized fashion with the highest priority points made available first (highest voltages, WECC Path information, etc.). The WECC RC will ensure that the EHV system performance is acceptable prior to making lower-priority ICCP data

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/Monitoring%20of%20Disturbance%20Control%20Performance.pdf

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/Monitoring%20of%20System%20Frequency%20and%20Balancing%20Authority%20Performance.pdf

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/Monitoring%20of%20System%20Frequency%20and%20Balancing%20Authority%20Performance.pdf

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/WECC%20Reliability%20Coordinator%20Communication%20Protocol.pdf

http://www.wecc.biz/awareness/Reliability/WECC%20RC%20Operating%20Procedures/Emergency%20Operations%20Procedure.pdf



points available. The milestones assume that all required TOPs and BAs that are providing the ICCP data have signed the WECC Universal NDA. If they have not signed the NDAs, then the milestones will slip accordingly.

It is important to note that if the EHV system performance is not acceptable at any time, there will need to be a data-sharing project defined with the users of the service. If the need arises, a cost to be shared by the service users for additional servers and possibly an FTE will be identified.


Develop process for BAs and TOPs to request read permission of available points

In Progress November 1, 2012

Make highest priority data points available to signatories of the Universal NDA


Review EHV system performance and make additional data points available

Not Started March 1, 2013

3.1.26 Survey of Western Interconnection Practices (O&P1)

Based on a letter from David Nevius, Senior Vice President of NERC, WECC initiated a survey of TOPs, TPs, PCs, RCs, GOs, and GOPs on processes and practices across the Western Interconnection. The survey was distributed on June 10, 2012, with an initial due date of July 2, 2012. WECC published a summary of results from the survey, including identified reliability gaps and best practices on July 20, 2012. WECC is currently following up with non-responders.


Issue Survey COMPLETE June 10, 2012

Summarize initial results COMPLETE July 20, 2012

Identify and publish best practices and reliability gaps


Follow-up with non-responders In Progress September 30, 2012

Executive follow-up for continued non-responders

Scheduled October 31, 2012

http://www.wecc.biz/library/WECC%20Documents/Publications/Summary%20of%20Sept%208%20Survey%20Result.pdf



3.1.27 Best Practices for Next-Day Studies (O&P2)

The recommendations of the Joint Report associated with next-day studies included several items for inclusion in the studies. The Operating Practices Subcommittee (OPS) will develop a guideline outlining the recommended best practices for parameters of next-day studies, including:

• Development of best practices for contingency analysis

• Development of a common methodology and format that will include working with the WECC RC to facilitate use of the RC-posted case as well as integrating these practices into their daily process

• Identification of appropriate elements for inclusion, including internal and external facilities as well as sub-100-kV elements


Initial meeting of OPS leadership COMPLETE August 9, 2012

Meeting of full OPS COMPLETE August 21-22, 2012

First draft of guideline Not Started November 2012

Approval of guideline by Operating Committee (OC) (special meeting)

Not Started January 2013

3.1.28 Consistent Mechanism for Seasonal Planning (O&P3)

There were several gaps associated with seasonal planning that were identified through the survey. Most of these gaps dealt with inconsistencies in system conditions (e.g., outages, facilities for inclusion, contingencies considered, shoulder periods) included, as well as inconsistencies in process (participation in subregional study groups). WECC is working to facilitate a consistent mechanism for seasonal planning. In addition, the seasonal study process will be improved to stress the importance of communication and coordination between planners performing the seasonal studies and the operations staff tasked with operating the system.




Initial meeting with subregional study groups COMPLETE August 8, 2012

Identify and document roles of subregional study groups

In Progress January 31, 2013

Enhance process to ensure consistency and coordination of all seasonal studies


Identify an organization with centralized responsibility for oversight


Develop process for N-1 contingency analysis for complete WECC footprint


3.1.29 Ensure Coverage of Planning Coordinators (PC) (O&P4)

WECC has identified that gaps exist in coverage of PCs in the Western Interconnection. WECC is investigating possible solutions to address these gaps and will develop a comprehensive report along with recommendations for WECC Board consideration and action.


Review PC requirements in standards In Progress October 15, 2012

Discuss at the Planning Coordination Committee (PCC)

Scheduled October 21-22, 2012

Develop comprehensive report on PC gaps and recommendations

Not Started February 15, 2013

Discuss and make recommendation at Board of Directors

Not Started March 13-15, 2013

Final implementation plan Not Started December 2013



3.1.30 Model Relays and RAS in Base Cases (O&P5)

Relays and Remedial Action Schemes (RAS) are currently not modeled in base cases or in most TOP studies. It was identified in the survey that the most efficient way to facilitate modeling of relays and RAS by TOPs would be to include them in the base cases. This process will include identifying which relays and RAS should be modeled, and is not intended to model all relays and RAS.

Membership of the task force working on this issue will have a representative from each of the following:

OC .......................... Operating Committee

PCC ........................ Planning Coordination Committee

TSS ........................ Technical Studies Subcommittee

RASRS ................... Remedial Action Scheme Reliability Subcommittee

SRWG .................... System Review Work Group

RWG ....................... Relay Work Group

MVWG .................... Modeling and Validation Work Group

WECC RC .............. WECC Reliability Coordinator

NERC Staff

WECC Staff

The draft Scope of Work including finalization of membership and task force leadership will be finalized by October 5, 2012 with a tentatively scheduled face-to-face kickoff meeting planned in conjunction with the WECC Standing Committee meetings the week of October 8. WECC is actively participating in the NERC System Analysis and Modeling Subcommittee (SAMS) work on modeling and simulating RAS.


Task force under RASRS developed to identify which RAS should be modeled


Draft scope developed for RASRS task force COMPLETE September 13, 2012

Finalize scope for RASRS task force In Progress October 5, 2012

Finalize membership of task force In Progress October 12, 2012




Develop process for identifying what relay and RAS information is necessary


Identify confidentiality issues Not Started December 31, 2012

Identify modeling capabilities needed for including relays and RAS


Develop models of relays and RAS Not Started July 31, 2014

Get models included in simulation programs Not Started December 31, 2014

Revise Data Preparation Manual Not Started March 30, 2015

Issue data request Not Started March 30, 2015

Incorporate selected relays and RAS into base cases


3.1.31 RASRS Review Additional Tie-line Schemes and Safety Nets (O&P6)

In support of this effort, the Remedial Action Scheme Reliability Subcommittee (RASRS) chair sent a data request to all Western Interconnection TOPs for them to provide information on any tie-line scheme and/or safety nets. Staff is working with the RASRS chair and representatives from the Bonneville Power Administration (BPA), Pacific Gas and Electric Company (PG&E), Southern California Edison (SCE), and NERC staff to establish a task force within RASRS that will not only review this additional data but also review the current RAS definitions in the PRC-012-014 Regional Criterion.

This effort will involve a review of the existing RAS definitions, development of a mechanism for awareness of these tie-line schemes (RC, TOPs), and a process for sharing this RAS data with planning staff of TOPs for incorporation into the planning models. As part of the modeling process, any interaction with other protection systems will be assessed as well. The original data request resulting from the implementation of the PRC-012-014 Regional Criterion has been successful in gathering data on existing schemes as well as identifying several new schemes (i.e., Safety Nets and Local Area Protection Schemes) that will be reviewed by RASRS. Currently the RASRS Chair and Staff Liaison are compiling the new RAS data submittals received and will provide these to both the RASRS and RAS Special Task Force for review.

http://www.wecc.biz/library/Documentation%20Categorization%20Files/Regional%20Criteria/PRC-012%20through%20014%20WECC-CRT-1%20Remedial%20Action%20Scheme%20Criterion%20Effective%2010-1-2011.pdf




The recent data request provided 25 new RAS from seven WECC members. This brings the total number of RAS to 218 with 64 WAPS, 134 LAPS and 20 safety nets. Review of this data will be done at RASRS meetings scheduled for November 7-9 and November 26-28, 2012.


RASRS Chair requesting additional data COMPLETE August 8, 2012

RASRS receiving additional data COMPLETE September 15, 2012

RASRS reviewing new data Not Started November 29, 2012

3.1.32 Interconnection-wide Coordination of TPL Assessments (O&P7)

WECC will develop a recommendation for coordination of Transmission Planning (TPL) assessments. This coordination will include an Interconnection-wide process for identifying and tracking corrective action plans related to system performance issues, as well as an Interconnection-wide assessment of system performance and information sharing. Information will also be shared with the RC for consideration in the operations timeframe.


Survey discussed at TSS meeting COMPLETE August 31, 2012

Survey distributed Not Started December 31, 2012

Recommendations discussed at January TSS meeting

Not Started January 2013

Recommendation presented to PCC for approval

Not Started March 2013

Recommendation presented to Board for approval

Not Started June 2013

3.1.33 Base Case Coordination System (O&P8)

WECC has been developing a Base Case Coordination System (BCCS) to validate data automatically, build power flow base cases, and store dynamic data in a centralized, Web-accessible database. The BCCS will be PSS/E and PSLF compatible. This will

http://www.wecc.biz/committees/StandingCommittees/PCC/20120807/Lists/Presentations/1/BCCS_IntroductionAugust072012.pdf



help improve consistency of data, decrease data errors, increase automation, improve data tracking, and provide centralized data storage. Although this project was started prior to September 8, 2011, it will help address some of the planning issues identified in the Joint Report.


RFP for BCCS vendor COMPLETE 2010

Vendor contracted COMPLETE December 2011

BCCS development In Progress November 30, 2012

WECC member training and implementation Not Started July 2013

3.1.34 Relay Operations Guideline (O&P9)

The survey identified inconsistencies in processes to review relays and assess settings. The Relay Work Group (RWG) will develop a guideline to define best practices and establish some consistency for review of settings for relays below 200 kV and assessing timing of relay settings to allow for manual action. The RWG will coordinate activities with the NERC System Protection and Control Subcommittee.


Initial meeting of RWG and RASRS chairs COMPLETE August 1, 2012

First draft of guideline In Progress November 2012

Final approval of guideline at OC (special meeting)

Not started January 2013

3.1.35 Benchmark TP Models Against September 8 Event Data (O&P10)

Recommendation 10 states that WECC dynamic models should be benchmarked by TPs against actual data from the September 8th event to improve their conformity to actual system performance. Finding 10 emphasizes that UFLS programs and automatic capacitor switching models need to be improved to get the simulation to match the event. WECC staff will provide the power flow and dynamics data used by NERC and FERC in the event investigation to TPs within the areas affected by the outage for the purpose of performing model validation. WECC will follow up with these entities to identify modeling deficiencies and track improvements.




WECC request for power flow and dynamics data from NERC and FERC


WECC receives signed NDAs and distributes data to appropriate entities for benchmarking

Not started October 31, 2012

TPs complete benchmarking and provide results to WECC

Updated UFLS and automatic capacitor switching models provided to WECC for inclusion in base case models

Not started

Not started

April 2013

June 2013

3.1.36 Sharing Real-time Data Among TOPs (O&P11)

In addition to sharing data between the WECC RC and TOPs, there is also a need for TOPs to share data among themselves. To increase situational awareness, the Critical Infrastructure and Information Management Subcommittee (CIIMS) and Data Exchange Work Group (DEWG) will develop a process for sharing real-time data among Registered Entities and increase situational awareness.

The development will include consideration of what data is currently shared, identification of sources of data, available methods of data sharing, and confidentiality issues. The resulting process will include defining participants, types of data, sample rates, and confidentiality processes.

CIIMS/ EMS Work Group (EMSWG) members and WECC staff (including RC staff) met via conference call on August 16, 2012 to discuss options of TOPs sharing data through the WECC RC or through adjacent entities. Cost effectiveness and staffing issues would need to be considered for each option. WECC will follow up with NERC on the NERC Project 2009-02: Real-time Reliability Monitoring and Analysis Capabilities as well as preparing the Real-time Tools Survey Analysis and Recommendations final report for distribution to all. The group believes the most effective effort would be to use the RTTBPTF report documents and Project 2009-02 White Paper as a starting point rather than recreate new WECC Guidelines. In addition, WECC will determine the status of NERC Project 2009-02 and engage Western Interconnection entities in this effort.




Initial meeting of CIIMS and DEWG chairs COMPLETE August 16, 2012

Develop draft process document (pending status of NERC Project 2009-02)


OC approval of process (if applicable) Not Started January 31, 2013

3.1.37 Distribute NERC RTTBPTF Report (O&P12)

The survey revealed that several TOPs were not aware of the report by the NERC Real-time Tools Best Practices Task Force (RTTBPTF). WECC has distributed the report to all TOPs in the Western Interconnection.


Distribute Report COMPLETE August 24, 2012

COMPLETE

3.1.38 Develop Real-time Tools Guideline (O&P13)

Although the NERC RTTBPTF developed a comprehensive report on best practices, the report is now four years old and may be out of date. It also may not consider some issues identified in the September 8, 2011 event. Therefore, the EMSWG will develop a guideline on real-time tools, perhaps as an update to the NERC RTTBPTF Report. Staff will follow up with NERC on NERC Project 2009-02: Real-time Reliability Monitoring and Analysis Capabilities and ascertain the status of the March 13, 2008 Real-time Tools Survey Analysis and Recommendations to determine what if any WECC Guidelines will be required.


Initial meeting of EMSWG and DEWG chairs COMPLETE August 16, 2012

Review NERC RTTBPTF Report In Progress September 30, 2012

Develop Guideline Not Started November 30, 2012

OC approval of Guideline Not Started January 31, 2013



3.1.39 Real-time Tools Training Guideline (O&P14)

In addition to the need for adequate real-time tools, the Joint Report also cited training on those tools as a gap. At the September 6, 2012 conference call, the OTS Chair and Manager of Training, determined that, rather than OTS developing a guideline on Real-time Tools training, they would instead coordinate with CIIMS and the EMSWG in their effort to review the NERC RTTBPTF Report and development of a Real-time Tools Guideline. Following completion of that effort, the OTS Task Force would develop a training module on the applicable elements of the RTTBPTF Report and the Real-time Tools Guideline and present this training as part of the WECC System Operator Training Program.


Initial meeting of OTS Chair and WECC Training Manager


Develop draft training module Not Started December 16, 2012

OTS review and approval of training module Not Started January 16, 2013

3.1.40 Address Discrepancies Between Planning and Operations Models (O&P15)

To address discrepancies between planning and operations models, WECC is focusing on the major WECC models: the WSM and the planning base cases. WECC has developed the West-wide System Model Base Case Reconciliation Task Force (WBRTF) to address this reconciliation. Work continues on correlating bus numbers with node identifiers and other data, including generator representations, between models.


WBRTF Established COMPLETE June 2012

Develop process for continued reconciliation In Progress November 30, 2012

Identify and resolve discrepancies with membership


Coordinate updates to planning base cases (as necessary) with members





WECC RC update WSM (as necessary) In Progress June 30, 2014

3.1.41 Guideline on Sub-100-kV Elements in Models (O&P16)

The Joint Report identified modeling of sub-100-kV elements in multiple time horizons. WECC believes that the modeling should be consistent throughout time horizons to the extent possible and is developing a guideline specifying which sub-100-kV elements should be included.


Identify or form a group to address In Progress October 21, 2012

Develop Guideline Not Started July 31, 2013

Revise Data Preparation Manual Not Started October 31, 2013

3.1.42 Comprehensive Review of RAS (O&P17)

On October 1, 2011, Regional Criterion PRC-012 through 014-WECC-CRT-1: the Remedial Action Scheme Review and Assessment Plan became effective. This criterion requires TOs, GOs, and Distribution Providers to submit data on RAS, and to assess those RAS for operation, coordination, and effectiveness at least once every five years. RASRS then reviews all of the RAS data that has been submitted. As a part of this process, RASRS will review the San Onofre Nuclear Generating Station (SONGS) Separation Scheme and the S-line RAS during the November RASRS meetings. Continuing reviews of these and all other RAS will be an ongoing process. As part of the PRC-012-014 RAS Criterion annual data request that was completed in December 2011, the RAS Database includes 191 Schemes (59 Wide Area Protection Schemes, 13 Safety Nets, and 119 Local Area Protection Schemes).






PRC-012 through 014-WECC-CRT-1 effective COMPLETE October 1, 2011

First set of RAS data received COMPLETE December 31, 2011

Submit SAR to add requirement for additional information to PRC-(012-014)-WECC-CRT-2


Draft revision to PRC-(012-014)-WECC-CRT-2 posted for comment


Revised PRC-(012-014)-WECC-CRT-2 approval In Progress March 30, 2013

Review of SONGS Separation Scheme and S-Line RAS

In Progress November 28, 2012

Continuing comprehensive review of all RAS ONGOING ONGOING

3.1.43 Guideline on Post-Contingent Plans (O&P18)

The OPS will develop a guideline outlining best practices for developing and implementing post-contingent plans to mitigate system issues. This guideline will include consideration of the timing necessary for manual action in a post-contingent timeframe.


Initial conference call with OPS leadership COMPLETE August 9, 2012

Discussion at full OPS meeting COMPLETE August 22, 2012

Development of Guideline Not Started October 31, 2012

Approval by OC Not Started January 31, 2013

3.1.44 White Paper on Generator Acceleration Controls (O&P19)

Evaluation of the sensitivity of acceleration control functions in turbine controls systems to system events is a complex issue. To address this issue, the Control Work Group (CWG) and WECC staff will develop a white paper to identify the issues involved and further the discussion regarding what can be done. Evaluation of system performance during the September 8, 2011 event, as well as during other events, has indicated that



sometimes generators trip due to acceleration or frequency deviations and further exacerbate the effects of the event. The purpose of the white paper will be to investigate, with the generator manufacturers and owners, whether there are any steps that can be taken to identify the conditions under which generators trip and to improve models used for dynamic stability studies so the tripping can be predicted by the models.


Conference call with WECC staff and CWG leadership


Develop White Paper draft Not Started January 2013

Approval by OC Not Started June 2014

3.1.45 Generator Tripping in Base Cases (O&P20)

Dynamic simulations do not currently provide an indication of possible automatic generator tripping. To provide an indication of when generators may trip in event simulations, WECC will add a default generator tripping model to WECC base cases in a monitor-only mode so that future studies by WECC and its members will have an indication of possible generator tripping.


Add the default generator protection model to the WECC master dynamics file

In Progress October 12, 2012

3.1.46 Review of Elements to Add to BES (O&P21)

On June 22, 2012, FERC issued a Notice of Proposed Rulemaking to approve NERC’s revised Definition of Bulk Electric System. This definition establishes a bright-line 100-kV threshold along with several bright-line inclusions and exclusions. The revised definition has an associated exceptions process whereby entities can include or exclude additional facilities with sufficient technical justification. It is expected that WECC will have a role in requesting inclusion exceptions through this process. WECC’s review and process will be consistent with any Final Rule from FERC on this issue.

http://www.nerc.com/docs/standards/sar/bes_definition_third_posting_roadmap_20111107_clean.pdf

http://www.nerc.com/docs/standards/sar/bes_definition_third_posting_roadmap_20111107_clean.pdf




Review elements identified by the WECC RC for inclusion in models

In Progress July 2013

Determine additional criteria necessary for inclusion in the BES

Not Started December 2013

Coordinate criteria with NERC processes In Progress December 2013

Begin initial review of elements Not Started January 2014

Ongoing analysis of elements Ongoing Ongoing

3.1.47 Consider RTDS (O&P22)

A WECC cross-functional team will meet with Southern California Edison to gain a better understanding of their Real-time Digital Simulation (RTDS) tool. WECC will then discuss whether the tool would be feasible for use and provide sufficient benefit to justify the cost on an Interconnection-wide basis.


Meet with SCE to learn more about RTDS Not Started March 31, 2013

Discuss merits of exploring use of RTDS on an interconnection-wide basis


3.1.48 Add Standards to Audit Scope (CPL1)

WECC will consider the findings and recommendations from the Joint Report when performing risk assessments and audit scope determination for future audits to supplement the standards and requirements in the Actively Monitored List (AML). The standards considered will be standards that could have some protection against outages of the type experienced on September 8, 2011. The changes to the audit scope will include consideration of entity size and type of facilities, and may result in different standard sets for these entities. Audits that were scheduled for the third and fourth quarter 2012 have been expanded to include the standards and requirements listed below. These are in addition to standards already on the NERC Tier 1 AML and WECC Compliance Monitoring and Enforcement Program Implementation Plans.



• FAC-014-2 R4, R5 • MOD-010 R1, R2 • MOD-012 R1, R2 • PRC-015 R1 R3 • TPL-002 R1, R2, R3

• TPL-003 R1, R2


Identification of Standards for addition to audit scope as appropriate

COMPLETE May 29, 2012

Continual review of audit scope ONGOING ONGOING

COMPLETE

3.1.49 Add “Areas of Concern” to Audit Reports (CPL2)

While continuing to audit to the explicit language contained in the standards, auditors will add to audit reports any recommendations or suggestions to enhance reliability. The expectation continues that entities will respond to “Areas of Concern” to address compliance issues. Recommendations or suggestions are intended to enhance reliability even if the entity is already in compliance with the standards.


Communication of change to audit staff COMPLETE July 2012

Memo to auditors memorializing practice COMPLETE September 24, 2012

COMPLETE

3.1.50 Meetings Between Compliance and the WECC RC (CPL3)

The RC and Compliance each have unique insight into the processes and practices of entities throughout the Western Interconnection. As reliability concerns arise, the two groups have varying abilities to affect change. By discussing trends and general concerns among the groups from a high-level perspective, both groups can most effectively address issues. Compliance and the RC are developing regular meetings to discuss any identified trends or areas of concern. WECC will establish written guidelines to establish appropriate parameters of communications to ensure that staff maintains the correct level of confidentiality. At all times during these communications, the WECC RC and Compliance Monitoring staff will maintain confidentiality, and each group will



abide by the confidentiality provisions identified in the NERC Rules of Procedure, WECC Bylaws, and other governing documents.


Develop scope, periodicity, and ground rules of meetings


Hold meetings ONGOING ONGOING

3.1.51 Coordinate with NERC on Issues (CPL4)

Compliance management and staff will continue to coordinate with NERC to identify and address issues. With respect to WECC Compliance monitoring activities; WECC will review the standards, entities, and functions noted in the Joint Report and will work with NERC to identify needs for enhanced monitoring activities or improvements in monitoring techniques.


WECC work with NERC to review issues and identify opportunities for improvement

In Progress February 28, 2013

3.2 WECC Member and Registered Entity Activities

In addition to the work underway at WECC, the members and Registered Entities have also expressed a commitment to improving reliability and addressing the issues identified in the Joint Report and in Mr. Cauley’s letter. Many members and Registered Entities have taken action to review and improve their own systems, practices, and processes.

Table 2 lists the individual WECC member and Registered Entity activities completed, underway, or planned in response to the event on September 8, 2011. This information has been voluntarily shared with WECC and is therefore not comprehensive. While many entities already had processes or practices in place prior to September 8, 2011 that address some of the recommendations, these activities are not listed. In addition, entity involvement in WECC-led activities is not specifically identified. WECC encourages all entities to coordinate with WECC on their efforts.



Activity Legend: APS ......... Arizona Public Service

BPA ......... Bonneville Power Administration

CAISO ..... California Independent System Operator

IID ........... Imperial Irrigation District

PGE ........ Portland General Electric

PNM ........ Public Service Company of New Mexico

SCE ......... Southern California Edison Company

SDG&E ... San Diego Gas & Electric Company

Table 2: WECC Member and Registered Entity Activities

Entity Activity Status Estimated Completion Date

APS1 APS Enhance and share next-day studies COMPLETE June 2012

APS2 APS Develop procedures for next-day studies and sharing of such information


APS3 APS Compare next-day study results to real-time data COMPLETE June 2012

APS4 APS Expand next-day studies to include external facilities In Progress October, 2012

APS5 APS Conduct external contingencies in seasonal studies In Progress December 2012

APS6 APS Share seasonal studies with additional TOPs COMPLETE June 2012

APS7 APS Expand seasonal studies In Progress December 2012

APS8 APS Expand near- and long-term planning studies In Progress December 2012

APS9 APS Benchmark WECC dynamic models In Progress February 2013

APS10 APS Improve real-time external visibility In Progress June 2013

APS11 APS Implement state estimator and RTCA In Progress June 2013





APS12 APS Ensure Adequacy of Post-contingency Mitigation Plans In Progress December 2012

APS13 APS Create procedure to notify the WECC RC/TOPs if RTCA ceases to operate

In development June 2013

APS14 APS Identify valid SOLs and IROLs COMPLETE June 2012

APS15 APS Evaluate Generator Acceleration Control Sensitivity In Progress December 2012

APS16 APS Evaluate SOLs related to relay settings In Progress March 2013

APS17 APS Confirm transformer overload protection relay settings In Progress December 2012

APS18 APS Phase angle difference following loss of transmission line In Progress December 2013

BPA1 BPA Assure conservative limits COMPLETE August 16, 2012

BPA2 BPA Perform next-day studies using state estimator cases In Progress March 2013

BPA3 BPA Implement state estimator and RTCA In Progress June 2013

BPA4 BPA Implement 24/7 study engineer support In Progress May 31, 2015

BPA5 BPA Review of Dispatcher Standing Orders for sufficiency and accuracy of RAS

In Progress December 2013

BPA6 BPA Expand dispatch alarms for outages that impact SOLs In Progress March 2013

BPA7 BPA Participate in NWPP Outage Coordination Task Force In Progress Unknown

CAISO1 CAISO Expand next-day studies to include external facilities In Progress February 2013

CAISO2 CAISO Expand Seasonal Planning to include external facilities COMPLETE June 2012

CAISO3 CAISO Review need for RAS In Progress March 2013

CAISO4 CAISO Perform Dynamic Data Validation In Progress March 2013





CAISO5 CAISO Expand visibility in real-time tools In Progress February 2013

CAISO6 CAISO Revise SOL/IROL methodology consistent with WECC RC COMPLETE June 2012

CAISO7 CAISO/SCE Assess SONGS separation scheme In Progress March 2013

CAISO8 CAISO Increase real-time awareness of angular separation In Progress December 2012

IID1 IID Improve next-day studies In Progress August 31,2012

IID2 IID Share next-day studies with adjacent BAs/TOPs and WECC RC


IID3 IID Expand next-day studies In Progress May 31, 2013

IID4 IID Conduct full contingency analysis in seasonal studies In Progress December 31, 2012

IID5 IID Revise seasonal study process In Progress December 31, 2012

IID6 IID Include protection systems in seasonal planning process In Progress December 31, 2012

IID7 IID Benchmark actual performance against planned performance In Progress December 31, 2012

IID8 IID Include all critical facilities in current-day analysis In Progress May 31, 2013

IID9 IID Review and revise RTCA model, procedures, and training In Progress September 15, 2012

IID10 IID Review and enhance RTCA application In Progress May 31, 2013

IID11 IID Review Emergency Operations Procedures COMPLETE July 31, 2012





IID12 IID Review and revise relay settings In Progress March 31, 2012

IID13 IID Implement procedure related to monitoring system conditions In Progress October 31, 2012

IID14 IID Review procedures related to mitigating loading violations COMPLETE July 31, 2012

IID15 IID Review SOLs and potential IROLs In Progress December 31, 2012

IID16 IID/CAISO/ SDG&E

Revisit S-Line RAS settings In Progress November 30, 2012

IID17 IID Review sensitivity of generator acceleration control COMPLETE July 16, 2012

IID18 IID Review facility ratings In Progress December 31, 2012

IID19 IID Develop procedures and associated training related to closing lines with large phase angle differences


PGE1 PGE Implement dedicated transmission operations In Progress December 31, 2012

PGE2 PGE Establish process to coordinate outages with TOPs and BAs In Progress January 31, 2012

PGE3 PGE Implement multiple scenarios in seasonal studies In Progress Unknown

PGE4 PGE Formalize process for sharing relay trip settings In Progress Unknown

PGE5 PGE Implement state estimator and RTCA In Progress January 2013

PGE6 PGE Review post-contingency mitigation plans In Progress Unknown

PGE7 PGE Evaluate sensitivity of generator acceleration control In Progress January 2013

PGE8 PGE Establish process to review impact of RAS In Progress Unknown





PGE9 PGE Update relay settings In Progress August 2013

PNM1 PNM Post next-day studies on WECCRC.org COMPLETE

PNM2 PNM Implement state estimator and expand capabilities COMPLETE June 4, 2012

PNM3 PNM Review NERC RTTBPTF Report In Progress December 2012

PNM4 PNM Compare real-time model against planning model COMPLETE

PNM5 PNM Review SOLs and potential IROLs COMPLETE June 4, 2012

PNM6 PNM Remove unnecessary relay In Progress December 31, 2012

PNM7 PNM Increase the use of external data

SCE1 SCE Review sensitivity of acceleration control functions COMPLETE July 2012



3.2.1 APS will Enhance and Share Next-day Studies (APS1)

Prior to September 8, 2011, APS performed general next-day studies through use of the Arizona Security Monitoring Manual (ASMM) studies and seasonal operating studies. Through these studies, APS system operators identified operating adjustments needed following the planned or unplanned outage of a transmission facility without the need to generate a unique day-ahead study for each day. Upon request, APS system engineers would supplement the ASMM next-day studies by creating unique next-day studies to address system conditions where appropriate. Beginning on June 1, 2012, APS also began generating unique day-ahead studies for each day. APS shares the results of these next-day studies by posting to the WECCRC.org website.


Create unique next-day studies COMPLETE June 2012

Share results of next-day studies COMPLETE June 2012

COMPLETE

3.2.2 APS will Develop Procedures for Next-day Studies (APS2)

APS is developing a new procedure for the next-day study process and sharing the results of that process. This activity includes training of applicable staff.


Develop procedure for next-day studies COMPLETE August 15, 2012

COMPLETE

3.2.3 APS will Compare Next-day Studies to Real-time Data (APS3)

APS now periodically compares the results for the next-day studies to the actual information for that day to ensure accuracy, and compares real-time data to planning models on a limited basis.


Compare next-day studies to real-time data COMPLETE June 2012

COMPLETE



3.2.4 APS will Expand Next-day Studies to Include External Facilities (APS4)

APS is acquiring data from neighboring TOPs and BAs on generation and transmission outages, and will implement non-disclosure agreements as necessary to facilitate the exchange of next-day operations. APS is also analyzing how to include additional external sub-100-kV facilities that can impact BES reliability.


Acquire data for external facilities In Progress October 1, 2012

Include sub-100-kV external facilities In Progress December 1, 2012

3.2.5 APS will Include External Contingencies in Seasonal Studies (APS5)

APS is conducting an analysis to identify contingencies outside its own system that can impact the reliability of the BES within its system.


Include external contingencies in seasonal studies


3.2.6 APS will Share Seasonal Studies with Additional TOPs (APS6)

Prior to September 8, 2011, the results of APS’s Summer and Winter Operating Studies were routinely shared electronically with IID, Western Area Power Administration (WAPA), Salt River Project (SRP), Tucson Electric Power Company (TEPC), and the WECC RC. Since September 8, 2011, APS has expanded the distribution of this information to also include entities such as SCE, PNM, CAISO, SDG&E, Los Angeles Department of Water and Power (LADWP), NV Energy (NVE), and Southwest Transmission Cooperative, Inc. (SWTC). APS will also provide these studies to other TOPs upon request. In addition, the ASMM is shared with the following entities at least annually and as changes to the ASMM are made: IID, SRP, WAPA, the WECC RC, SDG&E, EPE, CAISO, SCE, LADWP, TEPC, and NVE.


Share seasonal studies with additional TOPs COMPLETE June 2012

COMPLETE



3.2.7 APS will Expand its Seasonal Studies (APS7)

APS is in the process of expanding the study focus of seasonal planning to include external facilities that impact BES reliability. APS will hire additional engineering staff to support additional study work, including expanding the cases on which APS runs individual planning studies to include multiple base cases, generation maintenance outages, and dispatch scenarios during high-load shoulder periods.


Expand seasonal studies to include external facilities


Hire additional staff to support additional study scenarios


3.2.8 APS will Expand Near- and Long-term Planning Studies (APS8)

APS currently evaluates the impact of all N-1 outages within the APS footprint, including major transmission outages, and the impact of protection systems in post-contingent conditions. The near- and long-term planning covers critical system conditions and considers internal sub-100-kV facilities and some external sub-100-kV facilities. APS is continuing to develop and enhance its study cases that cover critical system conditions over the planning horizon.


Expand near- and long-term planning studies In Progress December 2012

3.2.9 APS will Benchmark WECC Dynamic Models (APS9)

Based on the APS review, an improvement in the governor model of one of the combustion turbine units at Yuma was recently provided to WECC for implementation in the dynamic data file. Dynamic models for all generating units are based on verified tests and/or system events.


Benchmark dynamic models In Progress February 1, 2013



3.2.10 APS will Improve Real-time External Visibility (APS10)

APS is working to obtain sufficient data to monitor significant external facilities in real-time, especially those that are known to have a direct impact on the reliability of the system.


Improve external real-time visibility In Progress June 2013

3.2.11 APS will Implement State Estimator and RTCA (APS11)

APS is developing a state estimator and RTCA tools to provide operators with enhanced situational awareness to assist them in identifying and planning for contingencies.


Implement state estimator and RTCA In Progress June 2013

3.2.12 APS will Ensure Adequacy of Post-contingency Mitigation Plans (APS12)

APS is reviewing existing operating processes and procedures to ensure that post-contingency mitigation plans reflect the time necessary to take mitigating actions, including control actions, to return the system to a secure N-1 state as soon as possible, but no longer than 30 minutes following a single contingency. As part of that analysis, APS is reviewing the effect of relays that automatically isolate facilities to determine whether they provide operators sufficient time to take mitigating measures.


Ensure adequacy of post-contingency mitigation plans


3.2.13 APS will Develop Procedures to Notify the RC for Loss of RTCA (APS13)

APS will, upon completion of its RTCA, develop and implement procedures to notify the WECC RC and neighboring TOPs and BAs promptly after losing RTCA capabilities. This will include training the operators on the new procedure.


Procedure to notify RC for loss of RTCA In Progress June 2013



3.2.14 APS Identified Valid SOLs and IROLs (APS14)

APS worked with the WECC RC and other parties to develop a Hoodoo Wash-North Gila Nomogram and flow mitigation procedure, and determined that Hassyampa-North Gila is not an IROL. APS continues to work with the WECC RC and other entities to determine whether other facilities should be recognized as IROLs, as appropriate.


Developed Hoodoo Wash-North Gila Nomogram COMPLETE June 1, 2012

COMPLETE

3.2.15 APS will Evaluate Generator Acceleration Control Sensitivity (APS15)

None of the units in the APS system, other than the Palo Verde Nuclear Generating Station (PVNGS), use an acceleration control function to trip a unit on the transmission system. APS will further assess the sensitivity of generator acceleration control, which will include the PVNGS.


Evaluate sensitivity of generator acceleration control


3.2.16 APS will Evaluate SOLs Related to Relay Settings (APS16)

APS’ facility ratings methodology requires that the rating be equal to the most limiting piece of equipment, including relay settings. APS is currently reevaluating facility ratings, methodologies, and the implementation of the methodologies to ensure compliance and ensure that the settings do not unnecessarily restrict transmission loadability.


Evaluate SOLs related to relay settings In Progress March 1, 2013

3.2.17 APS will Confirm Transformer Overload Protection Relay Settings (APS17)

APS is currently reviewing relay settings on transmission lines and transformers to ensure appropriate margins are between relay settings and emergency ratings developed by TOPs. This evaluation will include a determination of whether the settings can be raised to provide more time for operators to take manual action to mitigate overloads that are within the short-time thermal capability of the equipment.




Confirm relay settings In Progress December 1, 2012

3.2.18 APS will Develop Tools to Determine Phase Angle Differences (APS18)

APS installed a Phasor Measurement Unit (PMU) at the North Gila and Hoodoo Wash substations that will enable the operator to determine the phase angle differences when the line is de-energized. APS is developing a project schedule to add additional PMUs to its system on other line segments and is planning to install additional PMUs for all existing 500-kV and 345-kV substations where they are not already in place. APS has updated procedures and provided training for adding PMUs and mitigating phase angle differences.


Install PMUs at North Gila and Hoodoo Wash COMPLETE July 17, 2012

Add additional PMUs at all 500-kV and 345-kV substations


Update procedures and provide training for mitigating phase angles

COMPLETE May 2012

3.2.19 BPA will Assure Conservative Limits for Contingencies (BPA1)

The Bonneville Power Administration (BPA) reviewed all WECC Path Catalog paths under BPA jurisdiction to assure that they have conservative limits for contingencies and are incorporated in Dispatcher Standing Orders.


Review limits for contingencies COMPLETE August 16, 2012

COMPLETE

3.2.20 BPA will Perform Next-day Studies using State Estimator Cases (BPA2)

BPA had foundational work for study automation underway, and has expanded that work to include performing next-day studies using state estimator cases. BPA is currently defining steps for implementation.




Perform next-day studies using state estimator cases

In Progress March 2013

3.2.21 BPA will Implement a State Estimator and RTCA (BPA3)

BPA is accelerating its project to implement a state estimator and RTCA, including modeling RAS, for system operators. BPA’s effort will include coordinating the WECC RC’s WSM with BPA’s network model.


Implement state estimator and RTCA In Progress June 2013

3.2.22 BPA will Implement 24/7 Study Engineer Support (BPA4)

BPA is phasing in 24/7 study engineering support to run RTCA and state estimator studies. BPA is in the process of developing tools, duties, responsibilities, and methods.


24/7 study engineering support In Progress May 31, 2015

3.2.23 BPA will Review Dispatcher Standing Orders for Sufficiency and Accuracy of RAS (BPA5)

BPA is performing a comprehensive review and update as needed to BPA's Dispatcher Standing Orders (DSO) for sufficiency and accuracy of RAS. Roughly 50 DSOs have been identified for review, and roughly 20 percent have been reviewed and updated.


Review Dispatcher Standing Orders In Progress December 2013

3.2.24 BPA will Expand Dispatch Alarms for Outages that Impact SOLs (BPA6)

BPA is implementing an expansion of dispatch alarms for internal and external outages that impact SOLs by using real-time electrical status.




Expand dispatch alarms In Progress March 2013

3.2.25 BPA will Participate in the NWPP Outage Coordination Task Force (BPA7)

BPA is participating in the Northwest Power Pool (NWPP) Outage Coordination Task Force with the goal of assessing and improving regional outage coordination effectiveness.


Participate in NWPP Outage Coordination Task Force

In Progress

3.2.26 CAISO will Expand Next-day Studies to Include External Facilities (CAISO1)

CAISO shares next-day studies with the WECC RC. CAISO executed the Universal NDA to allow data sharing with neighboring TOPs. In addition, CAISO is expanding its network model to include external areas.


Share next-day studies with WECC RC COMPLETE August 2012

Execute Universal NDA COMPLETE April 2012

Expand network model to include external area In Progress February 2013

3.2.27 CAISO to Expand Seasonal Planning to Include External Facilities (CAISO2)

CAISO performs summer and winter seasonal assessments that assess the entire CAISO-controlled grid, regardless of its voltage level. The seasonal assessments take into account potential differences in generation dispatch and other topologies.


Expand seasonal planning to include external facilities

COMPLETE June 2012

COMPLETE



3.2.28 CAISO to Review Need for RAS (CAISO3)

CAISO is conducting a planning review of all RAS as part of the 2012/2013 annual ten-year transmission planning cycle. This effort will be coordinated with and provide input into the future review of detailed RAS designs to be performed by transmission owners.


Review RAS for continued need In Progress March 2013

3.2.29 CAISO to Perform Dynamic Data Validation (CAISO4)

CAISO will perform dynamic data validation by benchmarking simulation results against actual events and measured system performance of September 8, 2011. CAISO transmission planning cases are being developed in coordination with participating transmission owners for the 2012/2013 transmission planning cycle. In addition, CAISO is working with the participating transmission owners to coordinate necessary enhancements to dynamic models. CAISO uses dynamic models provided by its participating transmission owners who are registered NERC Transmission Planners for the CAISO system and are primarily responsible for maintaining system models. CAISO is aware of two specific changes at this time to the planning system dynamic models as a result of the September 8 analysis:

• SDG&E updated underfrequency load shedding models to include updated definite-time, underfrequency load shedding relay data for various buses

• SDG&E updated under- and over-frequency generation tripping data

Operation study power flow and dynamic models have been enhanced to include more complete modeling of the Imperial Irrigation District.


Validated dynamic data In Progress March 2013

3.2.30 CAISO to Expand Visibility in Real-time Tools (CAISO5)

CAISO has taken several steps to expand visibility in real-time tools for operator situational awareness. The IID system data, APS-Yuma data, and Western Area Lower Colorado (WALC) data will be deployed in the full network model. CAISO has also reduced the RTCA cycle from 15 minutes to five minutes. Finally, CAISO updated procedure 5410 to include notification of the WECC RC and neighboring TOPs and BAs promptly after losing RTCA, and is in the process of training operators.




IID system in full network model COMPLETE August 16, 2012

APS-Yuma in full network model In Progress December 19, 2012

WALC in full network model In Progress February 28, 2013

Reduced RTCA cycle from 15 minutes to five minutes

COMPLETE December 2011

Update procedure to notify WECC RC, TOPs, and BAs for loss of RTCA, and train operators


3.2.31 CAISO to Revise SOL/IROL Methodology Consistent with WECC RC (CAISO6)

CAISO participated in the WECC RC effort to define its revised SOL methodology. CAISO has Procedure 3100 that provides guidelines in SOL and IROL establishment process, consistent with the WECC RC methodology.


Establish SOL/IROL methodology consistent with WECC RC

COMPLETE June 2012

COMPLETE

3.2.32 CAISO and SCE to Assess SONGS Separation Scheme (CAISO7)

CAISO has developed a RAS review study plan that will be executed as part of the 2012/2013 transmission planning cycle. This study plan will provide the functional review results of the higher priority RAS necessary for the TOs, and will help them prioritize their detailed design reviews. As part of the CAISO 2012/2013 study effort, CAISO will assess the need for periodic reviews and anticipates developing a framework for more frequent reviews (at least for different classes of RAS) than the minimum review requirement of once every five years.

CAISO and SCE coordinated with SDG&E and the WECC RC on assessing the need for the San Onofre 220-kV System Separation Scheme with the SONGS units out of service. Based on that assessment, the separation scheme was temporarily deactivated for the duration of the two SONGS unit outages with new system additions and topology changes for the summer of 2012. The installation of SCE’s undervoltage load shedding



scheme and SDG&E’s Safety Net ensure reliable system operation while the system separation scheme is temporarily disabled.

SCE and CAISO are evaluating new designs for the San Onofre 220-kV System Separation Scheme so it would meet the requirements of a RAS and avoid SONGS units tripping if activated.


RAS review study plan executed In Progress March 2013

Assess need for more frequent review of RAS In Progress March 2013

Review need for SONGS separation scheme with both units out

COMPLETE June 2012

Review need for SONGS separation scheme with one or two units in service


3.2.33 CAISO to Increase Real-time Awareness of Angular Separation (CAISO8)

CAISO is enhancing its RTCA tool to detect potential angular separation between two substations.


Add angular separation to RTCA In Progress December 2012

3.2.34 IID to Improve Next-day Studies (IID1)

IID will take several steps to improve their next-day study analysis, including developing and implementing a Normal Operations Procedure related to next-day studies as well as archiving of base cases used and adding references to specific base cases.




Include archiving bases cases and referencing specific base cases to process

COMPLETE November 1, 2011

Develop Normal Operating Procedure COMPLETE May 30, 2012

Implement Normal Operating Procedures In Progress September 27, 2012

Provide training on new procedure for all personnel In Progress September 27, 2012

3.2.35 IID Share Next-day Studies with Adjacent BAs/TOPs and WECC RC (IID2)

IID has signed the WECC Universal Non-Disclosure Agreement and now has access to WECCRC.org. IID shares its next-day studies with adjacent BAs/TOPs and the WECC RC.


Access to WECCRC.org COMPLETE August 6, 2012

Share next-day studies COMPLETE August 6, 2012

COMPLETE

3.2.36 IID Include Appropriate Facilities in Next-day Studies (IID3)

IID will revise its next-day studies to include external data and facilities, and internal sub-100-kV facilities that have been identified as impacting the BES. IID will use seasonal studies and identification from external entities to determine which external facilities to study. IID has started modeling the data and is in the process of collecting additional data from external entities.




Include identified internal 92-kV facilities COMPLETE November 3, 2011

Model and create displays for external data In Progress September 6, 2012

Implement first 50 external data points In Progress January 8, 2013

Implement final 50 external data points Not Started March 21, 2013

Analysis of network expansion for external data Not Started May 14, 2013

Inclusion of external facilities above 100 kV In Progress May 14, 2013

Inclusion of external facilities below 100 kV In Progress May 31, 2013

3.2.37 IID will Conduct Full Contingency Analysis in Seasonal Studies (IID4)

IID will conduct full contingency analysis to identify the contingencies external to IID’s system that could impact its reliability. This will include developing a consistent contingency list to be used as a benchmark for seasonal and long-term planning, and developing a system operating procedure to share seasonal studies with TOPs that are shown to affect or be affected by the identified contingencies.


Conduct full contingency analysis and share seasonal studies


3.2.38 IID will Revise its Seasonal Study Process (IID5)

IID will confirm that seasonal planning studies include external and internal facilities that could impact the BES, including any sub-100-kV facilities. IID will also revise the existing process to consider expanding the seasonal studies to include multiple scenarios and base cases. IID will also create a system operating procedure to establish communication between the planning and operations processes. The seasonal planning process will also be revised to include overload relay trip settings on transformers and transmission lines that impact the BES, including those set below 150 percent of their normal rating or 115 percent of the highest rating.




Include internal and external facilities, including those below 100 kV that can impact the Bulk Electric System


Expand seasonal studies to include multiple scenarios and base cases


Create standard operating procedure for communication between planning and operations


Include relay settings in seasonal studies In Progress December 31, 2012

3.2.39 IID will Include Protection Systems in Seasonal Planning Process (IID6)

IID will develop study cases that cover critical system conditions over the planning horizon; consider the benefits and potential adverse effects of all protection systems (including RAS and overload protection schemes); study the interaction of the RAS; and consider the impact on reliability of elements operated at less than 100 kV.

This process includes requesting information from California ISO, CFE, WALC, APS, SDG&E, and SCE.


Include protection systems in seasonal planning process


3.2.40 IID will Benchmark Actual Performance Against Planned Performance (IID7)

IID will develop a procedure to model planned performance and benchmark against actual performance on an ongoing basis, using WECC dynamic models.


Develop process for benchmarking In Progress December 31, 2012

3.2.41 IID will Include All Critical Facilities in Current-day Analysis (IID8)

IID will identify the internal and external critical facility data to implement in current-day analysis.




Implement internal critical facility data COMPLETE November 3, 2011

Identify external data to be included in EMS COMPLETE April 8, 2012

Implement external critical facility data In Progress May 21, 2013

Implement displays for external data in EMS In Progress May 31, 2013

3.2.42 IID will Review and Revise RTCA Model, Procedures, and Training (IID9)

IID will review its RTCA application to ensure that it represents critical facilities needed for the reliable operation of the BES. IID will also review and revise its RTCA procedure. Finally, IID will train its system operators on the RTCA tool.


Review and revise RTCA application In Progress May 31, 2013

Review and revise RTCA procedure COMPLETE September 15, 2012

Provide training to System Operators on RTCA application and procedure


3.2.43 IID will Review and Enhance RTCA Application (IID10)

IID will enhance its RTCA application to include alarm functionality when results indicate violations of equipment ratings. IID also reviewed its RTCA application to determine if the tool is adequate, operational, and runs frequently enough to provide the System Operator with the situational awareness necessary to identify and plan for contingencies. IID determined that the tool is operational and runs frequently enough. Additional alarming functionality was implemented. IID is in the process of obtaining additional data on external facilities.


Review for operability and frequency of running COMPLETE April 8, 2012

Add alarms COMPLETE May 15, 2012

Obtain data on external critical facilities In Progress May 31, 2013



3.2.44 IID will Review Emergency Operations Procedures (IID11)

IID reviewed its Emergency Operations Procedures to ensure that plans include provisions for post-contingency mitigation plans that allow enough time for the System Operators to return the system to a secure N-1 state as soon as possible, but no longer than 30 minutes. IID implemented a procedure related to the mitigation of transformer and transmission line overloading on interconnected facilities. IID worked with the WECC RC, CAISO, APS, WALC, SDG&E, SCE, and CFE to jointly develop the procedure “WECC RC Monitoring of the Imperial Valley and San Diego Areas.”


Review and implement revised Emergency Operations Procedures


COMPLETE

3.2.45 IID will Review and Revise Relay Settings (IID12)

IID will review all relay settings that automatically isolate transformers and transmission lines to ensure that they provide system operators sufficient time to take mitigating measures in existing processes and procedures. This review will also ensure that there are appropriate margins between relay settings and emergency ratings developed by transmission providers.

Initial changes have included installing additional relays with revised settings at the Coachella Valley Substation, Ramon Substation, El Centro Switching Station, and Niland Substation. IID is also installing additional relays with revised settings at Pilot Knob, Midway, Highline, and Avenue 58.


Review 230-kV line relay settings COMPLETE May 4, 2011

Install additional relays at CV, Ramon, El Centro, Niland


Install additional relays at Pilot Knob, Midway, Highline, Avenue 58

In Progress March 31, 2013

Review settings on 161-kV transmission lines In Progress March 31, 2013



3.2.46 IID will Implement a Procedure Related to Monitoring System Conditions (IID13)

IID will implement a procedure related to monitoring system conditions.


Develop and implement procedure In Progress October 31, 2012

3.2.47 IID will Review Procedures Related to Mitigating Loading Violations (IID14)

IID will review all procedures related to mitigating loading violations (SOLs and IROLs). IID received the WECC RC procedure, provided a copy of the procedure to the IID system operators, and performed an annual review of the emergency operating plan that identified procedures for mitigating SOL and IROL violations.


Receive and distribute WECC RC procedure COMPLETE July 31, 2012

Review IID EOP Plan COMPLETE April 18, 2012

COMPLETE

3.2.48 IID will Review SOLs and Potential IROLs (IID15)

IID will work with the WECC RC and TOPs to consider whether Path 44 and the Hassyampa – North Gila line should be recognized as IROLs. IID will evaluate and coordinate existing SOLs to ensure that they take into account all transmission and generation facilities and protection systems that impact the reliability of the BES.


Evaluate Path 44 and Hassyampa-North Gila In Progress December 31, 2012

Evaluate and coordinate SOLs In Progress December 31, 2012

3.2.49 IID, SDG&E and CAISO will Revisit S-Line RAS Settings (IID16)

IID will revisit the S-Line RAS protection settings to ensure coordination with other protection systems to prevent adverse impact to the BES, premature operation, or excessive isolation of facilities. IID is currently in the process of reviewing the S-line RAS design with the WECC RC, SDG&E, and CAISO. The generator tripping portion of the scheme has been disabled. IID will provide suggested revised S-Line RAS tripping



values to SDG&E, WECC RC, and CAISO. IID will periodically review, along with the WECC RC and SDG&E, the purpose and impact of the RAS.


Generator tripping portion of S-Line RAS has been disabled


Coordinate S-Line tripping values COMPLETE August 24, 2012

Review S-Line RAS with RASRS In Progress November 28, 2012

3.2.50 IID Reviewed Sensitivity of Generator Acceleration Control (IID17)

IID reviewed the sensitivity of the acceleration control functions in turbine control systems to determine whether transient perturbations or fault conditions in the transmission system result in unit acceleration that would trip the unit without allowing time for protective devices to clear the fault on the transmission line. IID determined that none of their turbines incorporate a turbine trip on acceleration.


Review acceleration control functions COMPLETE July 16, 2012

COMPLETE

3.2.51 IID will Review Facility Ratings (IID18)

IID will review the facility rating methodologies and implementation to ensure that IID’s ratings are equal to the most limiting piece of equipment, including relay settings. IID will define the process associated with establishing relay settings that affect emergency ratings.


Review facility rating methodologies In Progress December 31, 2012

3.2.52 IID will Develop Procedures and Associated Training Related to Closing Lines with Large Phase Angle Differences (IID19)

The IID EMS SCADA system does not currently have the functionality to determine the phase angle difference following the loss of lines. IID will develop procedures related to closing lines with large phase angle differences, and provide training on these



procedures. IID will also explore options for determining phase angle differences and providing contingency analysis related to angular differences and closing lines.


Develop procedures for closing lines with large phase angle differences


Provide training on new procedures Not Started December 31, 2012

Explore options for determining phase angle differences


Explore options for providing contingency analysis related to phase angle differences


3.2.53 PGE will Implement Dedicated Transmission Operations (PGE1)

Portland General Electric (PGE) will create a transmission operations group. PGE’s Transmission Operations section will run the next-day studies and use the state estimator during normal business hours. The state estimator will continue to operate and be available to dispatchers 24/7. This section will initially be operational with current resources and fully functional with backup support, succession planning, etc., with additional positions in the 2013 budget request.


Implement dedicated transmission operations In Progress December 2013

3.2.54 PGE will Establish a Process to Coordinate Outages with TOPs and BAs (PGE2)

PGE is evaluating the adequacy of existing procedures. Planned outages are currently coordinated with the WECC RC and surrounding TOPs and BAs through the WECC Coordinated Outage System. Unplanned outages are coordinated using the PGE “SCC Responsibility to the Reliability Coordinator” procedure.


Evaluate existing procedures In Progress January 2013



3.2.55 PGE will Implement Multiple Scenarios in Seasonal Studies (PGE3)

PGE will expand its seasonal study process to include scenarios for spring and fall shoulder periods, as well as multiple load levels and generation patterns.


Implement multiple scenarios In Progress Unknown

3.2.56 PGE will Formalize a Process for Sharing Relay Trip Settings (PGE4)

PGE will develop a formalized procedure for sharing relay trip settings with neighboring TOPs and BAs.


Implement procedure for sharing relay trip settings In Progress Unknown

3.2.57 PGE will Implement a State Estimator and RTCA (PGE5)

PGE will develop a functional state estimator and RTCA system. A consultant was scheduled to be on site the week of September 17 to support this work. Once the RTCA is operational, PGE will revise the procedure “SCC Responsibility to the Reliability Coordinator” to include notification of the RC for loss of RTCA capability.


Implement state estimator In Progress December 31, 2012

Implement RTCA In Progress December 31, 2012

Revise procedure for notification of loss of RTCA Not Started January 31, 2013

3.2.58 PGE will Review Post-contingency Mitigation Plans (PGE6)

PGE will review post-contingency mitigation plans to verify that they can be executed within 30 minutes.


Review post-contingency mitigation plans In Progress Unknown



3.2.59 PGE will Evaluate Sensitivity of Generator Acceleration Control (PGE7)

PGE will evaluate the sensitivity of generator acceleration control functions and modify as necessary.


Review sensitivity In Progress January 2013

3.2.60 PGE will Establish Process to Review Impact of RAS (PGE8)

PGE is planning to establish a process to periodically review any impact of RAS.


Establish review process In Progress Unknown

3.2.61 PGE will Update Relay Settings (PGE9)

PGE will review transformer relay settings to ensure adequate margins, and will update any settings that are identified to have insufficient margins.


Review and update relay settings In Progress August 2013

3.2.62 PNM will Post Next-day Studies on WECCRC.org (PNM1)

PNM signed the WECC Universal NDA and now posts multiple next-day studies and results on WECCRC.org for sharing with other signatories of the Universal NDA. PNM coordinates with neighboring entities to help improve the accuracy of next-day study models.


Sign Universal NDA COMPLETE March 28, 2012

Post next-day studies on WECCRC.org COMPLETE

COMPLETE

3.2.63 PNM will Implement State Estimator and Expand Capabilities (PNM2)

PNM implemented a state estimator and associated real-time tools. PNM is in regular contact with its neighbors to coordinate exchange of topology data, Inter-control Center Communications Protocol (ICCP) object data for breaker and switch indication, and



facility flow and voltage readings as PNM and its neighbors extend their state estimation capability and contingency data bases.


State estimator and RTCA capability released COMPLETE May 22, 2012

Training and full implementation of state estimator and RTCA


Coordinate with neighbors to expand capabilities ONGOING ONGOING

COMPLETE

3.2.64 PNM will Review the NERC RTTBPTF Report (PNM3)

PNM is reviewing the NERC RTTBPTF report to consider future changes to real-time tools.


Review Report In Progress December 31, 2012

3.2.65 PNM will Compare Real-time Models Against Planning Models (PNM4)

After deploying the state estimator, PNM began comparing the real-time network model against the planning model for verification. Monthly discussions between the appropriate operations and planning personnel are used to ensure consistency between the models on an ongoing basis.


Compare Models COMPLETE June 2012

Monthly meetings between planning and operations ONGOING ONGOING

COMPLETE

3.2.66 PNM Reviewed SOLs and Potential IROLs (PNM5)

PNM reviewed SOLs per the enhanced WECC RC SOL Methodology, including a review for any potential IROLs.




Review SOLs and potential IROLs COMPLETE June 4, 2012

COMPLETE

3.2.67 PNM will Remove an Unnecessary Over-current Relay (PNM6)

PNM has only one transformer with over-current backup that could impact the reliability of the BES. PNM has reviewed the relay and has determined that the over-current backup is not needed as the over-temperature protection will protect the transformer. PNM will remove the unnecessary over-current relay.


Remove over current-relay In Progress December 31, 2012

3.2.68 PNM will increase the use of external data (PNM7)

PNM is continuing to work with other TOs to acquire ICCP object data for facilities that are beyond the boundaries of the PNM BA to further strengthen next-day and real-time system studies and overall situational awareness.


Acquire ICCP object data

3.2.69 SCE will Review the Sensitivity of the Acceleration Control Functions (SCE1)

SCE reviewed and reported that SONGS does not intend to change the sensitivity of the acceleration control functions of the turbine control systems that are established under the jurisdiction of the Nuclear Regulatory Commission (NRC). The acceleration control function of the SONGS turbine control system, along with mechanical design features, are responsible for keeping the mechanical stresses in the turbine blades and rotor to a level that the probability of low-pressure turbine blade failure, ejection and subsequent damage to the reactor containment building is sufficiently low. Settings for the acceleration control functions were determined and put in place prior to commercial operation of the SONGS units.

The NRC has accepted that these analyses demonstrate the probability of low-pressure turbine blade failure is sufficiently low in conjunction with an operating license condition



that requires periodic testing of the turbine over speed trip system and verification of the turbine steam admission (stop/governor) valve’s ability to close upon demand.


Review acceleration control functions COMPLETE July 2012

COMPLETE

3.3 Recommended NERC Activities

Table 3 lists activities that WECC recommends that NERC consider. Many of the recommendations in the Joint Report address continent-wide issues that are or could be more fully addressed through NERC committees or actions.

In some cases, recommendations from the Joint Report address issues that are related to NERC Standards, but for which there is not an explicit standard requirement. Generally, NERC Standards describe “what” needs to be done, but not “how,” and therefore do not include specific tools or detailed processes. In such cases, WECC strongly encourages Registered Entities to review their systems, practices, and processes not only for compliance with the language of the requirement, but also for the intent of the standards and the best interest of the reliability of the Interconnection. For many of these recommendations, the associated WECC activity includes developing guidelines and best practices to give guidance to the industry on potential ways to address issues.

If NERC and FERC believe that recommendations must be mandatory for all Registered Entities, such issues are best addressed through clarifying and adding detail to NERC continent-wide standards. In such cases, WECC recommends that NERC develop SARs to make the appropriate changes to ensure that these activities apply continent-wide and not just to the Western Interconnection.

Table 3: Recommended NERC Activities

Activity

NERC1 Contingency Analysis

NERC2 Sub-100-kV Elements

NERC3 Parameters for Simulations

NERC4 Adequate Real-time Tools

NERC5 Notification of Loss of RTCA

NERC6 Sub-100-kV Relays

NERC7 Determination of Phase Angle Differences



Table 3: Recommended NERC Activities

Activity

NERC8 Generator Validation Standard Drafting Team

NERC9 Review TOP-003

NERC10 SAMS review Generator Control Issues

NERC11 Consider De-registration Process

NERC12 Consider Planning Coordinator Registration Gap Issues

3.3.1 Contingency Analysis (NERC1)

WECC recommends that NERC examine whether contingency analysis in real-time, next-day, and seasonal studies should be specifically required by standards. The various timeframes may need different requirements and may need to be addressed separately. If NERC believes that contingency analysis should be mandatory in any or all of the time frames, WECC recommends that NERC submit a SAR or a series of SARs to this effect.

3.3.2 Sub-100-kV Elements (NERC2)

To maintain consistency continent-wide, WECC recommends that NERC identify technically-based criteria for identifying which sub-100-kV elements must be modeled in the real-time, next day, seasonal, and near- and long-term horizons. NERC should also identify technically-based criteria for which sub-100-kV elements should be included in the Bulk Electric System. Such criteria must be consistent with any FERC-approved definition of the Bulk Electric System, and should clarify which facilities may be included through any FERC-approved exception process.

3.3.3 Parameters for Simulations (NERC3)

To maintain consistency continent-wide, WECC recommends that NERC consider developing guidelines or standard requirements identifying what base cases and parameters TOPs should use to conduct simulations. NERC should consider whether to specifically include certain bases cases, generation maintenance outages, and dispatch scenarios during high-load shoulder periods in such guidelines or requirements. WECC is currently developing a consistent mechanism for seasonal planning (O&P3), and would support collaboration and coordination with any such NERC effort.

3.3.4 Adequate Real-time Tools (NERC4)

To maintain consistency continent-wide, WECC recommends that NERC consider revising the Real-time Tools Best Practices Task Force Report to identify what constitutes adequate real-time tools. This revision can also account for changes in tools available since the 2008 release of the original report. WECC is currently developing a guideline for the Western Interconnection (O&P13), and would support collaboration



and coordination with any such NERC effort. This could include continuing work on NERC Project 2009-02: Real-time Reliability Monitoring and Analysis Capabilities.

3.3.5 Notification of Loss of RTCA (NERC5)

WECC recommends that NERC examine whether notification of the RCs and neighboring TOPs and BAs after loss of RTCA and other real-time tools should be mandatory. If NERC believes that it should be, WECC recommends that NERC submit a SAR to this effect.

3.3.6 Sub-100-kV Relays (NERC6)

WECC recommends that NERC review PRC-023-2 to determine whether there needs to be any additional inclusion of sub-200-kV relays. PRC-023-2 was not in effect on September 8, 2011.

3.3.7 Determination of Phase Angle Differences (NERC7)

WECC recommends that NERC examine whether tools to determine phase angle differences following the loss of lines and processes to mitigate reclosing of lines with large phase angle differences should be mandatory for all TOPs. If NERC believes that they should be, WECC recommends that NERC submit a SAR to this effect.

3.3.8 Generator Validation Standard Drafting Team (NERC8)

WECC recommends that NERC complete work of the NERC Generator Validation Standard Drafting Team (GVSDT) to develop PRC-024, which will include voltage and frequency ride-through requirements for new generators and reporting requirements for existing generators that cannot meet the voltage and frequency ride-through requirements. WECC anticipates that the PRC-024 reports can be used to provide guidance in modeling tripping of generators that trip within the voltage and frequency ride-through bands specified by the ride-through requirements.

3.3.9 Review TOP-003-2 (NERC9)

Requirement R1.1 of TOP-003-2 includes “a list of data and information needed by the Transmission Operator to support its Operational Planning Analyses and Real-time Monitoring.” NERC could consider modifying TOP-003 to require that the list of data required in 1.1 include the types of facilities required to be studied in next-day studies. In the current version, type of facility is not specifically called out, so it would have to be a decision by the TOP, or the standard could be modified to be more prescriptive.

3.3.10 SAMS Review Generator Control Issues (NERC10)

WECC understands that the NERC SAMS is currently reviewing generator control issues. WECC believes that it is appropriate for NERC to continue to maintain the lead on this issue and WECC would propose to coordinate with NERC on this activity.



3.3.11 Consider De-registration Process (NERC11)

WECC has identified issues related to the process to de-register or de-certify entities not capable of performing functions for which they are registered, and to transfer their responsibilities to other entities or require joint-registration organizations. First; there is no authority to force another entity to assume responsibility for compliance on behalf of the entity being de-registered or de-certified. Second; the NERC Rules of Procedure do not include provisions for de-registering or de-certifying entities. NERC would need to lead any changes to the Rules of Procedure to address this issue.

WECC raised this issue at the NERC Operating Committee Executive Committee meeting in September and understands that this issue will be discussed at the Reliability Issues Steering Committee (RISC) and the Certification and Registration Work Group (CRWG).

3.3.12 Consider Planning Coordinator Registration Gap Issues (NERC12)

The NERC Functional Model identifies three functions responsible for reliability planning: the Planning Coordinator, the Transmission Planner, and the Resource Planner. There is an implied intent that all of the Transmission Owners and Operators, Generator Owners and Operators, Load-Serving Entities, and Distribution Providers conduct their planning activities in coordination with one or more of these reliability planners. Additionally, the Planning Coordinator is tasked with coordinating with adjacent Planning Coordinators. However, the functional model also states that "while the area under the purview of a Planning Coordinator may include as few as one Transmission Planner and one Resource Planner, the Planning Coordinator's scope of activities may include extended coordination with integrated Planning Coordinator's plans for adjoining areas beyond individual system plans." Many Planning Coordinators have assumed the approach that they are a Planning Coordinator only for the functional registrations that are applicable to their own integrated company. There does not seem to be a method for ensuring that all of the functional registrations that must feed data into the Planning Coordinators are represented by one or more Planning Coordinators. The standards (PRC-023-2 for example) require that the GO/GOP obtain approval of the Planning Coordinator for the selection of certain load responsive relay settings. However there is not a corresponding requirement applicable to the PC to ensure that all GO/GOPs are covered by a PC.

The NERC FAQs on the Functional Model state that the Functional Model is not a Reliability Standard. "The Model defines the functions that must be performed to ensure that the bulk electric systems are planned and operated reliably." There is a question in the FAQs "Does the Planning Coordinator consider the Regional Council's planning standards when assessing the plan?" and is answered by "The Planning Coordinator assesses plans against NERC Reliability Standards." This answer directs the Planning Coordinator back to the Reliability Standards and therefore creates a circular reference.



WECC recommends that NERC review the gaps and references associated with the reliability planning functions and develop corresponding mechanisms to close the gaps.

3.4 Cross Referencing Activities to Recommendations and Systemic Issues

Many of the 27 recommendations from the Joint Report are addressed by a set of many activities listed in this Response Report. Table 4 cross-references the activities from Tables 1–3 to the 27 recommendations from the Joint Report. As an example, Recommendation 1 is addressed by WECC through activities RC1, RC2, and RC10, which provide for the RC to share next-day studies; O&P1 and O&P2, which identify best practices and recommend best practices for TOPs to conduct and share next-day studies; and CPL2, through which the Compliance Department can identify “Areas of Concern” if a TOP could improve its practices, even if it is technically compliant. Additionally, individual entities are addressing the recommendation as seen through activities APS1, APS2, APS3, BPA2, CAISO1, IID1, IID2, IID12, PGE1, and PNM1.

Table 5 cross-references the activities from Table 1–3 to the eight systemic issues identified by Gerry Cauley.



Activities Rec1 Rec2 Rec3 Rec4 Rec5 Rec6 Rec7 Rec8 Rec9 Rec10 Rec11 Rec12 Rec13 Rec14 Rec15 Rec16 Rec17 Rec18 Rec19 Rec20 Rec21 Rec22 Rec23 Rec24 Rec25 Rec26 Rec27

ORG1 ORG2 ORG3 ORG4 X ORG5 ORG6 X ORG7 RC1 X X RC2 X X RC3 X X RC4 X X RC5 X X RC6 X RC7 X RC8 X RC9 X RC10 X X X RC11 X RC12 X X RC13 X RC14 X RC15 X RC16 X RC17 RC18 X O&P1 X X X X X O&P2 X X X O&P3 X X X O&P4 X X X X O&P5 X X X O&P6 X O&P7 X O&P8 X O&P9 X X O&P10 X O&P11 X O&P12 X O&P13 X

Table 4: WECC Activities Completed or Underway in Response to the Joint Report




O&P14 X O&P15 X O&P16 X O&P17 X X X X O&P18 X O&P19 X O&P20 X O&P21 X X X O&P22 X X CPL1 X X CPL2 X X CPL3 CPL4 APS1 X APS2 X APS3 X APS4 X X APS5 X APS6 X APS7 X X X APS8 X APS9 X APS10 X APS11 X APS12 X APS13 X APS14 X APS15 X APS16 X X X APS17 X APS18 X BPA1 X BPA2 X BPA3 X X BPA4 X X BPA5 X BPA6 X BPA7 X





CAISO1 X X X CAISO2 X X X CAISO3 X CAISO4 X CAISO5 X X X X CAISO6 X CAISO7 X X X CAISO8 X IID1 X IID2 X IID3 X X IID4 X IID5 X X X IID6 X IID7 X IID8 X IID9 X X X IID10 X IID11 X IID12 X X X X IID13 X IID14 X IID15 X IID16 X X IID17 X IID18 X IID19 X PGE1 X PGE2 X PGE3 X PGE4 X PGE5 X X PGE6 X PGE7 X PGE8 X PGE9 X PNM1 X X PNM2 X X





PNM3 X PNM4 X PNM5 X PNM6 X PNM7 X X SCE1 X NERC1 X X NERC2 X X X X X NERC3 X NERC4 X NERC5 X NERC6 X NERC7 X NERC8 X NERC9 X X NERC10 X NERC11 NERC12 X X X X




Table 5: Reference of Activities to Eight Systemic Issues

Systemic Issues Activities

WECC Reliability Coordinator Tools, Authorities, Capabilities, and Support

RC3 RC8 RC9 RC11 RC12 RC13 RC14 RC15 RC17 ORG4 ORG6 ORG7 O&P22

WECC Organization, Governance, and Conflict of Interest ORG1

WECC Path Ratings and Interconnection Reliability Operating Limits RC6 RC7 RC11 RC12

System Protection, Remedial Action Schemes, and Special Protection Systems

O&P5 O&P6 O&P9 O&P17 RC7

Data Sharing, Non-Disclosure, and Data Confidentiality Agreements ORG3 RC1 RC2 RC4 RC5 RC10 RC18

Roles and Responsibilities of Reliability Coordinator (RC), Balancing Authorities (BA), and Transmission Operators (TOPs)

RC1 RC2 RC4 RC5 RC6 RC8 RC17



Table 5: Reference of Activities to Eight Systemic Issues

Systemic Issues Activities

O&P13 O&P14 ORG3 ORG7

Awareness and Recognition of Impacts of Sub-100-kV Systems on bulk power system reliability

RC3 O&P2 O&P9 O&P13 O&P16 NERC11

ERO/Regional Entity (RE) Processes ORG1 ORG5 CPL1 CPL2 CPL3 CPL4

4 Conclusion

WECC is committed to reliability and many important activities are underway at WECC, its member companies, and its Registered Entities. The activities described in this Response Report outline important ongoing activities in response to the 27 recommendations in the Joint Report and the eight systemic concerns outlined in Gerry Cauley’s letter of July 26, 2012.

WECC will continue its leadership role; working with its members and Registered Entities to further enhance the reliability of the Western Interconnection and monitoring progress toward completion of any existing or new activities. WECC will initiate a program of regular reporting with FERC, NERC, the WECC Board of Directors, and WECC’s membership.

WECC commends the commitment of its membership and Registered Entities to improving reliability and addressing the recommendations of the Joint Report.


Update on Regulatory Matters (As of October 22, 2012)

Action None

Background Regulatory Matters in Canada

1. The second agreement among the North American Electric Reliability Corporation NERC, the Régie de l’Energie Québec and the Northeast Power Coordinating Council regarding implementation of mandatory Reliability Standards in Québec has been developed, and the agreement is under consideration by the provincial government. The Régie has issued a decision adopting a first group of Reliability Standards for Québec.

2. Manitoba has adopted all NERC Reliability Standards that were in effect as of March 2012 and is developing its process to adopt new and revised Reliability Standards.

3. British Columbia is considering vesting the British Columbia Utilities Commission with authority to levy monetary penalties for violations.

4. NERC has filed petitions for approval of interpretations of several Reliability Standards, as well as for approval of various proposed Reliability Standards in Alberta, British Columbia, National Energy Board (NEB) and New Brunswick.

5. New Brunswick is preparing legislation that will change how the reliability compliance and enforcement program is administered within the province.

6. On August 1, 2012, the Nova Scotia Utility and Review Board advised NERC in a letter that it has adopted a process to allow quick and efficient consideration and adoption of Reliability Standards submitted quarterly for approval by NERC.

7. NEB has concluded its consultation on a General Order (regulation) that would make relevant NERC Reliability Standards mandatory and enforceable on international transmission lines under its jurisdiction. NEB is developing an approach on Administrative Monetary Penalties that might be applicable, as appropriate.

8. On August 31, 2012, NERC filed its Second Quarter 2012 application for approval of Reliability Standards in Nova Scotia.

9. On September 24, 2012, NERC provide Notice of Filing of the NERC 2013 Business Plan and Budget (BPB) and the 2013 BPB of the Regional Entity and of Proposed Assessments to Fund Budgets to Alberta, Manitoba, NEB, Nova Scotia, Ontario and Saskatchewan.

http://www.nerc.com/files/Alberta_2013_Budget_Filing.pdf�



FERC Orders and Rulemakings Issued Since the Last Update

1. July 19, 2012 – The Federal Energy Regulatory Commission (FERC or Commission) issued a Proposed Policy Statement regarding allocation of capacity of new merchant transmission projects and new cost-based, participant-funded transmission projects. Docket Nos. AD12-9-000 and AD11-11-000.

2. July 19, 2012 – FERC issued Order No. 765 revising its regulations pertaining to its Continuity of Operations Plan which allows the Commission the discretion to better address not only long-term and catastrophic events, but also short-term events including loss of power or water. The Order allows for greater discretion regarding: the activation and deactivation of the Continuity of Operations Plan and any suspension of Commission operations, the length of time that the Continuity of Operations Plan is in effect and the length of time that Commission operations are suspended, the deactivation schedule and the resumption of full Commission operations, and the rescheduling of hearings, conferences and meetings. The Order also adds items to the list of requirements which are suspended when Commission operations are suspended which includes certain submittals by NERC. Docket No. RM12-13-000.

3. July 27, 2012 – FERC issued a Notice stating that it would not further review, on its own motion, the following Notices of Penalty (NOPs) in Docket Nos. NP12-32-000 Calpine Corporation and Calpine Power Management, LP, NP12-33-000 Louisville Gas & Electric and KU Services Company, NP12-34-000 Tennessee Valley Authority, NP12-35-000 Mesquite Power LLC, and NP12-36-000 Spreadsheet NOP.

4. August 2, 2012 – FERC issued an Order granting NERC’s request for reconsideration of the use of the Expedited Standards Development Process with regard to TPL-002-0b “footnote b.” Docket No. RM11-18-001.

5. August 3, 2012 - FERC issued an Order in which it denied clarification and rehearing of National Rural Electric Cooperative Association’s and American Public Power Association’s request for rehearing concerning CIP Version 4 Implementation. Docket No. RM11-11-001.

6. August 27, 2012 - FERC issued a Notice of a Technical Conference that FERC Staff will hold on the February 2011 Southwest Cold Weather Event. The first technical conference will be held on September 25, 2012 from 10:00 – 4:00 p.m. in Austin, Texas. The second technical conference will be held on September 27, 2012 from 10:00 – 4:00p.m in Albuquerque, New Mexico. The purpose of the technical conferences is to discuss actions taken in response to the August 16, 2011 Report on Outages and Curtailments during the Southwest Cold Weather Event of February 1-5, 2011 (Report). The technical conferences will explore the progress made on the Report’s recommendations and whether sufficient safeguards have been implemented to avert a repeat of the loss of generation due to severe cold weather. Docket No. AD11-9-000.

7. August 30, 2012 – FERC issued an Order granting rehearing on Wisconsin Electric’s request for clarification regarding the Commission’s discussion of coordination between automatic load shedding programs in PRC-006-1 and manual load shedding programs in EOP-003-2 in Order No. 763. Docket No. RM11-20-001.

8. August 30, 2012 – FERC issued a Notice stating that it would not further review, on its own motion, the following Notices of Penalty in Docket Nos. NP12-37-000 Unidentified

Registered Entity, NP12-38-000 Unidentified Registered Entity, NP12-39-000 TransAlta Centralia Generation, LLC, and NP12-40-000 Spreadsheet NOP.

9. September 13, 2012 – FERC issued a Letter Order approving NERC’s June 5, 2012 petition for approval of errata changes to seven Reliability Standards (BAL-005-0.1b, EOP-001-0b, EOP-001-2b, EOP-002-3, IRO-005-3a, PER-001-0.1 and TOP-002-2b). Docket No. RD12-4-000.

10. September 13, 2012 – FERC issued a Letter Order approving NERC’s filing that requested that the NERC Glossary of Terms be amended to modify the definition of “Interconnection Reliability Operating Limit (IROL)” by replacing the reference to “Cascading Outages” with “Cascading outages.” Docket No. RM06-16-000.

11. September 20, 2012 – FERC issued an Order accepting the May 14, 2012 Compliance Filing in response to the March 15, 2012 Compliance Enforcement Initiative (CEI) Order. Docket No. RC11-6-002.

12. September 20, 2012 – FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to approve regional Reliability Standard PRC-006-NPCC-1 (Automatic Underfrequency Load Shedding). Docket No. RM12-12-000.

13. September 20, 2012 – FERC issued a Final Rule on the Delegation of Authority of the Electric Reliability Organization’s (ERO) Budget, Delegation Agreement, and Policy and Procedure filings. This Final Rule delegates to the Director of the Office of Energy Market Regulation (OEMR) the ability to act on certain NERC filings involving budgets, business plans, delegation agreements and organization rules. Due to a recent internal reorganization, OEMR (rather than the Office of Electric Reliability) is now responsible for acting on these aforementioned filings. However, OEMR currently does not have delegated authority to act under section 215 of the Federal Power Act, which covers NERC activities and filings. The Final Rule grants OEMR the necessary delegated authority to act on such filings. Docket No. RM12-20-000.

14. September 28, 2012 – FERC issued a Notice stating that it would not further review, on its own motion, the following Notices of Penalty in Docket Nos. NP12-41-000 Entergy, NP12-42-000 Cedar Creek Wind Energy, LLC, NP12-43-000 Unidentified Registered Entity; and NP12-44-000 Spreadsheet NOP issued an Order stating that it would not further review, on its own motion, the following Notices of Penalty in Docket Nos. NP12-41-000 Entergy, NP12-42-000 Cedar Creek Wind Energy, LLC, NP12-43-000 Unidentified Registered Entity; and NP12-44-000 Spreadsheet NOP.

15. October 18, 2012 – FERC issued a Notice of Proposed Rulemaking (NOPR) on Revisions to Reliability Standards for Transmission Vegetation Management proposing to approve Reliability Standard FAC-003-2 (Transmission Vegetation Management, the three definitions in the petition, the implementation plan and the Violation Severity Levels associated with the proposed Reliability Standard). FERC proposes to direct that NERC revise the Violation Risk Factor for Requirement R2, and approve the remainder of the Violation Risk Factors. Docket No. RM12-4-000.

16. October 18, 2012 – FERC issued a Notice of Proposed Rulemaking (NOPR) proposing to direct NERC to develop and submit Geomagnetic Disturbance Reliability Standards (GMD Reliability Standards) that address the risks posed by geomagnetic disturbances (GMD) to the reliable operation of the Bulk Power System. Docket No. RM12-22-000.

NERC Filings Since the Last Update

1. July 23, 2012 – NERC submitted an informational filing containing the Presentation on the Effects from Geomagnetic Disturbances on the Bulk Power System by Mark Lauby at the Joint Meeting of the Nuclear Regulatory Commission (NRC) and FERC which was held on June 15, 2012 at FERC. Docket No. AD06-6.

2. July 30, 2012 – NERC submitted an informational filing in compliance with Paragraph 27 of Order No. 758 which contains a status report on PRC-005-2 and a project schedule for addressing reclosing relays in PRC-005-3. Docket No. RM10-5-000.

3. July 30, 2012 – NERC submitted a Petition for Approval of Amendments to ReliabilityFirst Corporation’s Delegation Agreement, including amendments to the Bylaws and Reliability Standards Development Procedure. Docket No. RR12-12-000.

4. July 30, 2012 – NERC submitted a Petition for Approval of Proposed Reliability Standards FAC-001-1 – Facility Connection Requirements, FAC-003-3 – Transmission Vegetation Management, PRC-004-2.1a – Analysis and Mitigation of Transmission and Generation Protection System Misoperations and PRC-005-1.1b - Transmission and Generation Protection System Maintenance and Testing. Docket No. RM12-16-000.

5. July 31, 2012 – NERC submitted an informational filing on the analysis of NERC Standards Process Results for the Second Quarter 2012 in compliance with an Order issued by FERC on January 18, 2007 and a subsequent Order on September 16, 2010. Docket Nos. RR06-1-000, RR09-7-000.

6. July 31, 2012 – NERC submitted its first quarterly report on the development status of BAL-003 - Frequency Response and Bias in compliance with FERC’s May, 4, 2012 Order and Order No. 693. Docket Nos. RM06-16-010 and RM06-16-011.

7. July 31, 2012 – NERC submitted a Notice of Penalty regarding an unidentified registered entity. Docket No. NP12-37.

8. July 31, 2012 – NERC submitted a Notice of Penalty regarding an unidentified registered entity. Docket No. NP12-38.

9. July 31, 2012 – NERC submitted a Notice of Penalty regarding TransAlta Centralia Generation, LLC. Docket No. NP12-39.

10. July 31, 2012 – NERC submitted its July 2012 Spreadsheet Notice of Penalty. Docket No. NP12-40-000.

11. July 31, 2012 – NERC submitted its July 2012 Find, Fix, Track and Report filing. Docket No. RC12-14-000.

12. August 1, 2012 – NERC submitted a petition for approval of interpretations of Reliability Standard CIP-004-4 - Personnel and Training, Requirements R2, R3, and R4, CIP-004-4a. Docket No. RD12-6-000.

13. August 1, 2012 – NERC submitted a petition for approval of interpretation of Reliability Standard CIP-002-4 — Critical Cyber Asset Identification, Requirement R3. Docket No. RD12-5-000.

14. August 3, 2012 – NERC submitted an errata to the Petition for Approval of Regional Reliability Standard PRC-006-NPCC-1 in which it includes the implementation plan in Exhibit A. Docket No. RM12-12-000.

15. August 9, 2012 – NERC submitted a compliance filing in Response to Order No. 763 on Automatic Underfrequency Load Shedding and Load Shedding Plans Reliability Standards. Docket No. RM11-20-000.

16. August 20, 2012 – NERC submitted an errata to correct the record regarding a petition for approval of interpretation of CIP-002-4. Docket No. RD12-5-000.

17. August 24, 2012 – NERC submitted its request for acceptance of NERC’s 2013 Business Plan and Budget Filing and the 2013 Business Plans and Budgets of the Regional Entities and for the approval of proposed assessments to fund budgets. Docket No. RR12-13-000.

18. August 24, 2012 – NERC submitted a Petition for Approval of Proposed Reliability Standard MOD-028-2 - Area Interchange Methodology. Docket No. RM12-19-000.

19. August 31, 2012 – NERC submitted the Second Quarter 2012 Compliance Filing of the North American Electric Reliability Corporation 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. This filing contains the referenced material pertaining to the second quarter of 2012. Docket No. RM06-16-000.

20. August 31, 2012 – NERC submitted a Notice of Penalty regarding Entergy. Docket No. NP12-41.

21. August 31, 2012 – NERC submitted a Notice of Penalty regarding Cedar Creek Wind Energy, LLC. Docket No. NP12-42.

22. August 31, 2012 – NERC submitted a Notice of Penalty regarding an unidentified registered entity. Docket No. NP12-43.

23. August 31, 2012 – NERC submitted its August 2012 Spreadsheet Notice of Penalty. Docket No. NP12-44.

24. August 31, 2012 – NERC submitted its August 2012 Find, Fix, Track and Report filing. Docket No. RC12-15.

25. September 4, 2012 – NERC submitted comments in response to FERC’s NOPR proposing to approve NERC’s modifications to the definition of the “Bulk Electric System.” Docket Nos. RM12-6-000 and RM12-7-000.

26. September 5, 2012 – NERC submitted a response to the motion of the Edison Electric Institute to extend the period for filing comments until September 28, 2012 and to shorten the response time to the 2013 Business Plans and Budgets of NERC and the eight Regional Entities. Docket No. RR12-13-000.

27. September 10, 2012 – NERC submitted an update to its request for acceptance of the 2013 Business Plans and Budgets of NERC, the eight Regional Entities and the Western Interconnection Regional Advisory Body, and approval of the proposed assessments to fund the 2013 budgets, which was originally filed in this docket on August 24, 2012. Docket No. RR12-13-000.

28. September 10, 2012 – NERC submitted a reply brief in response to the Response Brief of the Office of Enforcement Staff. Docket No. FA11-21.

29. September 19, 2012 – NERC submitted reply comments to the comments submitted in response to the NOPR on the Revisions to the ERO Definition of Bulk Electric System and Rules of Procedure. Docket Nos. RM12-6-000 and RM12-7-000.

30. September 20, 2012 – NERC submitted errata to the September 19, 2012 reply comments to the comments submitted in response to the NOPR on the Revisions to the ERO Definition of Bulk Electric System and Rules of Procedure. Docket Nos. RM12-6-000 and RM12-7-000.

31. September 24, 2012 – NERC filed comments in support of SERC Reliability Corporation’s response to the NOPR, issued on July 19, 2012, proposing to approve regional Reliability Standard PRC- 006-SERC-01 - Automatic Underfrequency Load Shedding Requirements. Docket No. RM12-9-000.

32. September 28, 2012 – NERC submitted the 2012 Annual Report on Wide-Area Analysis of Technical Feasibility Exceptions in compliance with Paragraphs 220 and 221 of Order No. 706, FERC’s January 21, 2010 Order Approving TFE Procedures and Ordering Compliance Filing, and Appendix 4D of the NERC Rules of Procedure. Docket No. RR10-1-001.

33. September 28, 2012 – NERC submitted a Notice of Penalty regarding an Unidentified Registered Entity. Docket No. NP12-45.

34. September 28, 2012 – NERC submitted its September 2012 Spreadsheet Notice of Penalty. Docket No. NP12-47.

35. September 28, 2012 – NERC submitted its September 2012 Find, Fix, Track and Report filing. Docket No. RC12-16.

36. October 12, 2012 – NERC submitted a filing in compliance with the September 20, 2012 Order requiring NERC to file training materials. FERC’s March 15 Order accepted NERC’s petition requesting approval of its proposal to make informational filings in a Find, Fix, Track and Report (FFT) spreadsheet format in connection with the Compliance Enforcement Initiative (CEI). These training materials are associated with the FFT initiative. Docket No. RC11-6.

37. October 15, 2012 – NERC submitted an errata filing to its September 28, 2012 Spreadsheet Notice of Penalty. Docket No. NP12-47.

Anticipated NERC Filings

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

2. October 31, 2012 – NERC will 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. October 31, 2012 – NERC will submit quarterly reports within 30 days of the end of each quarter, 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 Paragraph 85 of the September 16, 2010 Order on the Three-Year Performance Assessment). Docket Nos. RR09-7-000 and AD10-14-000.

4. November 26, 2012 – NERC will submit comments in response to the NOPR to approve PRC-006-NPCC-01.

5. November 30, 2012 – NERC will submit its quarterly Nuclear Reliability Standard filing in response to Paragraph 629 of Order No. 693. Docket No. RM06-16-000.

6. November 30, 2012 – NERC will submit a Nova Scotia Quarterly Filing of FERC Approved Reliability Standards.

7. February 15, 2013 (target) – NERC plans to submit a Violation Severity Level II follow-up filing.

8. March 15, 2013 – NERC will submit a compliance filing in response to the March 15, 2012 CEI Order. NERC also expects to submit a filing proposing improvements to the CEI on that date.